UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

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 333-215998

FTS INTERNATIONAL, INC.

(Exact Name of Registrant as Specified in Its Charter)

Delaware		30-0780081
(State or other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

777 Main Street, Suite 2900, Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

(817) 862-2000

(Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of each class		Name of each exchange on which registered
Common Stock, par value $0.01 per share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Securities Exchange Act of 1934:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

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 o No x

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 o No x

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 x No o

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. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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	o		Accelerated Filer	o
Non-Accelerated Filer	x	(Do not check if a smaller reporting company)	Smaller reporting company	o
Emerging growth company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of June 30, 2017, the last day of the registrant’s most recently completed second fiscal quarter, there was no public market for registrant’s common stock. The registrant’s common stock began trading on the New York Stock Exchange on February 2, 2018. As of March 7, 2018, aggregate market value of the common stock held by non-affiliates of the registrant was approximately $632.2 million, based on the closing price of the registrant’s common stock on March 7, 2018. As of March 7, 2018, the registrant had 109,274,564 shares of common stock, $0.01 par value, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

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Cautionary Statement Regarding Forward-Looking Statements

This annual report contains “forward-looking statements” that are subject to risks and uncertainties. All statements other than statements of historical or current fact included in this annual report are forward-looking statements. Forward-looking statements refer to our current expectations and projections relating to our financial condition, results of operations, plans, objectives, strategies, future performance and business. Forward-looking statements may be identified by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “anticipate,” “assume,” “believe,” “can have,” “contemplate,” “continue,” “could,” “design,” “due,” “estimate,” “expect,” “goal,” “intend,” “likely,” “may,” “might,” “objective,” “plan,” “predict,” “project,” “potential,” “seek,” “should,” “target,” “will,” “would” and other words and terms of similar meaning in connection with any discussion of the timing or nature of future operational performance or other events. For example, all statements we make relating to our estimated and projected costs, expenditures and growth rates, our plans and objectives for future operations, growth or initiatives or strategies are forward-looking statements. All forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those that we expect and, therefore, investors should not unduly rely on such statements. The risks that could cause these forward-looking statements to be inaccurate include but are not limited to:

· a decline in domestic spending by the onshore oil and natural gas industry;

· volatility in oil and natural gas prices;

· customers’ inability to maintain or increase their reserves going forward;

· deterioration in general economic conditions or a weakening of the broader energy industry;

· the competitive nature of the industry in which we conduct our business;

· the effect of a loss of, or financial distress of, one or more significant customers;

· nonpayment by customers we extend credit to;

· demand for services in our industry;

· actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

· a decline in demand for proppant;

· our inability to employ a sufficient number of key employees, technical personnel and other skilled or qualified workers;

· the occurrence of a significant event or adverse claim in excess of the insurance coverage we maintain;

· fines or penalties (administrative, civil or criminal), revocations of permits, or issuance of corrective action orders for noncompliance with health, safety and environmental laws and regulations;

· changes in laws and regulations which impose additional requirements or restrictions on business operations;

· federal, state and local regulation of hydraulic fracturing and other oilfield service activities, as well as exploration and production (“E&P”) activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;

· existing or future laws and regulations related to greenhouse gases and climate change;

· our ability to obtain permits, approvals and authorizations from governmental and third parties, and the effects of or changes to U.S. and foreign government regulation;

· restrictions on drilling activities intended to protect certain species of wildlife;

· conservation measures and technological advances which reduce demand for oil and natural gas;

· the level of global and domestic oil and natural gas inventories;

· the price and availability of alternative fuels and energy sources;

· the discovery rates of new oil and natural gas reserves;

· limitations on construction of new natural gas pipelines or increases in federal or state regulation of natural gas pipelines;

· the availability of water resources, suitable proppant and chemicals in sufficient quantities for use in hydraulic fracturing fluids;

· the cost of exploring for, developing, producing and delivering oil and natural gas;

· third party claims for possible infringement of intellectual property rights;

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Our Services

Hydraulic Fracturing

Our primary service offering is providing hydraulic fracturing services, also known as pressure pumping, to oil and natural gas E&P companies. These services are designed to enhance hydrocarbon flow in oil and natural gas wells, thus increasing the amount of hydrocarbons recovered. The development of resources in unconventional reservoirs, including oil and natural gas shales, is a technically and operationally challenging segment of the oilfield services market that has experienced strong growth worldwide, particularly in the United States.

Oil and natural gas wells are typically divided into one or more “stages,” which are isolated zones that focus the high-pressure fluid and proppant from the hydraulic fracturing fleet into distinct portions of the well and surrounding reservoir. The number of stages that will divide a well is determined by the customer’s proposed job design, and our customers typically compensate us based on each stage completed. Although the number and length of stages may vary by basin and formation characteristics, we have historically maintained a relatively consistent presence in each operating basin. During the last two years, as a result of our customers trending toward more intense completions, our quarterly average stage length, measured in minutes to complete, has increased by approximately 16%. Despite the longer average stage lengths, we have been able to increase our average stages per active fleet compared to the end of 2014. We were able to increase our average stage per active fleets because the primary contributor to the number of stages we complete in a quarter is our ability to reduce downtime on our equipment, rather than any variability in operating basins or formation characteristics. Therefore, we believe the number of stages that each of our active fleets completes in a given period of time is an important operating metric.

Hydraulic fracturing represents the largest cost of completing a shale oil or natural gas well. The process consists of pumping a fracturing fluid into a well casing or tubing at sufficient pressure to fracture the formation. The fracturing fluid primarily consists of water mixed with a small amount of chemicals and guar, forming a highly viscous liquid. Materials known as proppants, in our case primarily sand, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. Once the fractures are open, the fluid is designed to “break,” or reduce its viscosity, so that it will more easily flow back out of the formation. The proppants, which remain behind in the formation, act as a wedge that keeps the fractures open, allowing the trapped hydrocarbons to flow more freely. As a result of a successful fracturing process, hydrocarbon recovery rates are substantially enhanced; thus, increasing the return on investment for our customer. The amount of hydrocarbons produced from a typical shale oil or natural gas well generally declines quickly, with production from a shale well typically falling 60% to 70% in the first year. As a result, E&P companies must fracture new wells to maintain production levels.

We designed all of the hydraulic fracturing units and much of the auxiliary equipment used in our fleets to uniform specifications intended specifically for work in oil and natural gas basins requiring high pressures and high levels of sand intensity. Each of our fleets typically consists of 16 to 25 hydraulic fracturing units; two or more blenders (one used as a backup), which blend the proppant and chemicals into the hydraulic fluid; sand kings and other types of large containers used to store sand on location; various vehicles used to transport chemicals, gels and other materials; and various service trucks. Each hydraulic fracturing fleet includes a mobile, on-site control center that monitors pressures, rates and volumes, as applicable. Each control center is equipped with high bandwidth satellite hardware that provides continuous upload and download of job telemetry data. The data is delivered on a real-time basis to on-site job personnel, the customer and an assigned coordinator at our headquarters for display in both digital and graphical form.

Our hydraulic fracturing units consist primarily of a high-pressure pump, a diesel or combined diesel and natural gas engine, a transmission and various other supporting equipment mounted on a trailer. The high pressure pump consists of two key assemblies: the fluid-end and the power-end. Although the power-end of our pumps generally lasts several years, the fluid-end, which is the part of the pump through which the fracturing fluid is expelled under high pressure, is a shorter-lasting consumable, typically lasting less than one year. We refer to the group of hydraulic fracturing units, auxiliary equipment and vehicles necessary to perform a typical fracturing job as a “fleet” and the personnel assigned to each fleet as a “crew.” Our fleets operate primarily on a 24-hour-per-day basis, in which we typically staff three crews per fleet, including one crew with the day off. Our focus on 24-hour operations allows us to keep our equipment working for more hours per day, which we believe enhances our return-on-assets over time.

We primarily enter into service agreements with our customers for one or more “dedicated” fleets, rather than providing our fleets primarily for “spot work.” Under our typical dedicated fleet agreement, we deploy one or more of our hydraulic fracturing fleets exclusively to the customer to follow the customer’s completion schedule and job specifications until the agreement expires or is terminated in accordance with its terms. By contrast, under a typical spot work agreement, the fleet moves between customers as work becomes available. We believe that our strategy of pursuing dedicated fleet agreements leads to higher fleet utilization, as measured by the number of days each fleet is working per month, which we believe reduces our month-to-month revenue volatility and improves our revenue and profitability. See Note 2—“Summary of Significant Accounting Policies—Revenue Recognition” in Notes

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to our Audited Consolidated Financial Statements for discussion of pricing under our service agreements and revenue recognized for services.

An important element of hydraulic fracturing is the proper handling of the fracturing fluid. In all of our hydraulic fracturing jobs, our customers specify the composition of the fracturing fluid to be used. Sometimes this fluid includes products marketed by us. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well, and we are not involved in that process or in the disposal of the fluid. Our contracts generally require our customers to indemnify us against pollution and environmental damages originating below the surface of the ground or arising out of water disposal, or otherwise caused by the customer, other contractors or other third parties. In turn, we indemnify our customers for pollution and environmental damages originating at or above the surface caused solely by us.

Wireline Services

Our wireline services primarily consist of setting plugs between hydraulic fracturing stages, creating perforations within hydraulic fracturing stages and logging the characteristics of resource formations. Our wireline services equipment is designed to operate under high pressure in unconventional resource formations without delaying hydraulic fracturing operations. We currently provide wireline services in each of the areas where our hydraulic fracturing fleets operate. As of December 31, 2017, we owned 51 wireline units.

Industry Overview and Trends

The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by E&P companies to their well completions budget. The oil and natural gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of customer demand, the availability of pipeline capacity and other conditions and factors that are beyond our control.

The principal factor influencing demand for hydraulic fracturing services is the level of horizontal drilling activity by E&P companies. Since 2006, these companies have increasingly focused on exploiting the hydrocarbon reserves contained in North America’s unconventional oil and natural gas reservoirs by utilizing horizontal drilling and hydraulic fracturing. Over the last decade, advances in these technologies have made the development of many unconventional resources, such as oil and natural gas shale formations, economically attractive. These advancements led to a dramatic increase in the development of oil- and natural gas-producing basins in the United States and a corresponding increase in the demand for hydraulic fracturing services. Our industry grew rapidly until a significant decline in oil and natural gas prices from 2014 to 2016 caused a dramatic reduction in drilling and completion activity.

The significant decline in oil and natural gas prices that began in the third quarter of 2014 continued into February 2016, when the closing price of oil reached a 12-year low of $26.14 in February 2016. The horizontal rig count in the United States declined by 77%, from its peak of 1,372 rigs in November 2014 to a low of 314 rigs in May 2016, according to a Baker Hughes, Inc. report dated January 6, 2017. The reduced drilling activity led to a reduction in demand for hydraulic fracturing services and resulted in increased competition and lower prices for hydraulic fracturing services. The low commodity price environment caused a reduction in the completion activities of most of our customers and their spending on our services, which substantially reduced the prices we could charge our customers and had a negative impact on our activity levels during this period. We believe the financial distress of many other providers of hydraulic fracturing services led to significant maintenance deferrals and the use of idle fleets for spare parts, resulting in a material reduction in total deployable fracturing fleets.

Recently, oil prices have increased since the 12-year low recorded in February 2016, reaching a high of $64.89 in December 2017 and averaging $50.80 in 2017. As commodity prices have rebounded, we have experienced an increase in the level of demand for our services. Although our industry traditionally has been volatile, the following trends in our industry should benefit our operations and our ability to achieve our business objectives as commodity prices recover:

Large production growth from U.S. oil and natural gas formations. The average oil field production in the United States grew at a compound annual growth rate of 8.4% over the period from 2010 through 2016 due to production gains from unconventional reservoirs. According to the U.S. Energy Information Administration, or EIA, U.S. tight oil production grew from approximately 430,000 barrels per day in 2007 to over 4.6 million barrels per day in 2017 through November, representing 70% of total U.S. crude oil production in 2017 (as of the end of November). A majority of this increase came from the Permian Basin, the SCOOP/STACK Formation, the Marcellus/Utica Shale, the Eagle Ford Shale and the Haynesville Shale, which are our five operating basins, as well as

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the Williston Basin. We expect that this continued growth will result in increased demand for our services as commodity prices continue to stabilize or increase.

Increased use of horizontal drilling to develop high-pressure U.S. resource basins. The horizontal rig count as a percentage of the overall onshore rig count has increased every year since 2007, when horizontal rigs represented only approximately 25% of the total U.S. onshore rig count to approximately 86% at the end of 2017. We believe horizontal drilling activity will continue to grow as a portion of overall onshore wells drilled in the United States, primarily due to E&P companies increasingly developing unconventional resources such as shales. Successful economic production of these unconventional resource basins frequently requires hydraulic fracturing services like those we provide.

Faster drilling speed. The speed of drilling rigs is increasing significantly, which has increased the number of wells drilled for a given rig count. The speed of drilling means that more fracturing fleets are needed for every active drilling rig. On average there used to be four drilling rigs for each fracturing fleet, but that ratio is now less than 3-to-1, and continuing to decline. As a result, E&P companies are able to complete more stages using fewer rigs, and industry sources expect that total stages completed in 2017 will surpass 2014 levels at a significantly lower corresponding rig count.

Increasing completions intensity. Longer lateral lengths for horizontal wells and more sand per lateral foot require increased horsepower to execute a completion, which means that more fracturing units will be required for each fleet. The increased amount of sand per lateral foot also increases the wear-and-tear on each unit’s components and parts, which increases the repair and maintenance costs for each fleet. We expect that the projected increase in drilling speed and sand intensity will result in an increased demand for, and diminished supply of, pressure pumping services.

Reduced supply of hydraulic fracturing services from our competitors. The hydraulic fracturing industry in the United States is characterized by a few large providers (six with over 1 million horsepower), several medium sized providers (nine with between 1 million and 300,000 horsepower) and a significant number of smaller providers. We believe that many of these providers have been deferring or declining to repair their hydraulic fracturing equipment as it breaks down from ordinary use. This phenomenon of providers choosing to retire rather than repair broken equipment is often referred to as “attrition.” According to an industry report, the total working horsepower in North America declined from approximately 15 million in 2014 to approximately 6 million in 2016. Additionally, the large number of small service providers in our industry may make it an attractive candidate for industry consolidation, which would further reduce competition. These factors should lead to a better balance of supply and demand and to higher pricing levels for our services.

Completion of refracturings and drilled-but-uncompleted wells. As producing shale wells age, their level of production declines, typically falling 60% to 70% in the first year. Refracturing these wells can increase production levels. As the number and age of producing unconventional wells increases, the market for recompletions is expected to increase. In addition, because the cost of recompleting a well is generally lower than the total cost of drilling and completing a new well, the demand for recompletions is expected to increase relative to demand for new completions during depressed commodity price environments.

Potential development of international markets for our hydraulic fracturing services. There has been growing international interest in the development of unconventional resources such as oil and natural gas shales. This interest has resulted in a number of recently completed joint ventures between major U.S. and international E&P companies related to shale basins in the United States and acquisitions of significant acreage in shale basins in the United States by large, non-U.S. E&P companies. We believe that these acquisitions and joint ventures, which generally require the international partner to commit to significant future capital expenditures, will provide additional demand for hydraulic fracturing services in the coming years. Additionally, such activity may stimulate development of oil and natural gas shales outside the United States, such as the recent activity by our SinoFTS joint venture in Chongqing, China.

Increase in demand for oil and natural gas. The EIA projects that the average WTI price will increase through 2040 from growing demand and the development of more costly oil resources. The EIA also anticipates continued growth in long-term U.S. domestic demand for natural gas. We believe that as demand for oil and natural gas increases, E&P activity will rise and demand for our services will increase. Recent events including declines in North American production, attrition in the supply of horsepower in our industry and agreements by OPEC and certain other oil-producing countries to reduce oil production have provided upward momentum for energy prices. If near-term commodity prices stabilize at current levels or recover further, we expect a more active demand environment during 2018 and 2019 than was experienced in 2015 and 2016.

Competitive Strengths

We believe that we are well positioned because of the following competitive strengths:

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Large scale and leading market share across five of the most active major U.S. unconventional resource basins

With 1.6 million total hydraulic horsepower in our fleet, we are one of the largest hydraulic fracturing service providers in North America. We operate in five of the most active major unconventional basins in the United States, including the Permian Basin, the SCOOP/STACK Formation, the Marcellus/Utica Shale, the Eagle Ford Shale and the Haynesville Shale, which provide us exposure to a variety of oil and natural gas producers as well as geographies. We are one of the top three hydraulic fracturing providers across this operating footprint based on market share. According to an industry report from December 2017, these five operating basins will account for approximately 80% of well-completions spending in 2018 and 2019.

This geographic diversity reduces the volatility in our revenue due to basin trends, relative oil and natural gas prices, adverse weather and other events. Our five hydraulic fracturing districts enable us to rapidly reposition our fleets based on demand trends among different basins. Additionally, our large market share in each of our operating basins allows us to spread our fixed costs over a greater number of fleets. Furthermore, our large scale strengthens our negotiating position with our suppliers and our customers.

Pure-play, efficient hydraulic fracturing services provider with extensive experience in U.S. unconventional oil and natural gas production

Our primary focus is hydraulic fracturing. For the years ended December 31, 2016 and December 31, 2017, 95% of our revenues came from hydraulic fracturing services. From December 31, 2010 to January 8, 2018, we have completed more than 163,000 fracturing stages across five of the most active major unconventional basins in the United States. This history gives us invaluable experience and operational capabilities that are at the leading edge of horizontal well completions in unconventional formations.

We designed and assembled all of the hydraulic fracturing units and much of the auxiliary equipment used in our fleets to uniform specifications intended specifically for work in oil and natural gas basins requiring high pressures and high levels of sand intensity. In addition, we use proprietary pumps with fluid-ends that are capable of meeting the most demanding pressure, flow rate and proppant loading requirements encountered in the field.

In order to achieve the highest revenue potential and highest returns on our invested capital, we run all of our fleets in 24-hour operations allowing us to optimize the revenue-producing ability of our active fleets. In addition, rather than perform “spot work,” we prefer to dedicate each of our fleets to a specific customer, integrating our fleet into their drilling program schedule. These arrangements allow us to increase the number of days per month that our fleet is generating revenue and allow our crews to better understand customer expectations resulting in improved efficiency and safety.

In-house manufacturing, equipment maintenance and refurbishment capabilities

We manufacture and refurbish many of the components used by our fleets, including consumables, such as fluid-ends. We also perform substantially all the maintenance, repair and refurbishment of our hydraulic fracturing fleets, including the reactivation of our idle equipment. Our cost to produce components and reactivate idle fleets is significantly less than the cost to purchase comparable quality components and fleets from third-party suppliers. For example, we manufacture fluid-ends and power-ends at a cost that is approximately 50% to 60% less than purchasing them from outside suppliers. In addition, we perform full-scale refurbishments of our fracturing units at a cost that is approximately half the cost of utilizing an outside supplier. We estimate that this cost advantage saves us approximately $85 million per year at peak production levels. As trends in our industry continue toward increasing proppant levels and service intensity, the added wear-and-tear on hydraulic fracturing equipment will increase the rate at which components need to be replaced for a typical fleet, increasing our long-term cost advantage versus our competitors that do not have similar in-house manufacturing capabilities.

Our manufacturing capabilities also reduce the risk that we will be unable to source important components, such as fluid-ends, power-ends and other consumable parts. During periods of high demand for hydraulic fracturing services, external equipment vendors often report order backlogs of up to nine months. Our competitors may be unable to source components when needed or may be required to pay a much higher price for their components, or both, due to bottlenecks in supplier production levels. We have historically manufactured, and believe we have the capacity to manufacture, all major consumable components required to operate all 32 of our fleets at full capacity. We also designed and assembled all of our 32 existing fleets using internal resources and believe we can assemble new fleets internally at a substantial discount to the cost of buying them new from third-party providers.

Additionally, manufacturing our equipment internally allows us to constantly improve our equipment design in response to the knowledge we gain by operating in harsh geological environments under challenging conditions. This rapid feedback loop between our field operations and our manufacturing operations positions our equipment at the leading edge of developments in hydraulic fracturing design.

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Uniform fleet of standardized, high specification hydraulic fracturing equipment

We have a uniform fleet of hydraulic fracturing equipment. We designed our equipment to uniform specifications intended specifically for completions work in oil and natural gas basins requiring high levels of pressure, flow rate and sand intensity. The standardized, “plug and play” nature of our fleet provides us with several advantages, including: reduced repair and maintenance costs; reduced inventory costs; the ability to redeploy equipment among operating basins; and reduced complexity in our operations, which improves our safety and operational performance. We believe our technologically advanced fleets are among the most reliable and best performing in the industry with the capabilities to meet the most demanding pressure and flow rate requirements in the field.

Our standardized equipment reduces our downtime as our mechanics can quickly and efficiently diagnose and repair our equipment. Our uniform equipment also reduces the amount of inventory we need on hand. We are able to more easily shift fracturing pumps and other equipment among operating areas as needed to take advantage of market conditions and to replace temporarily damaged equipment. This flexibility allows us to target customers that are offering higher prices for our services, regardless of the basins in which they operate. Standardized equipment also reduces the complexity of our operations, which lowers our training costs. Additionally, we believe our industry-leading safety record is partly attributable to the standardization of our equipment, which makes it easier for mechanics and equipment operators to identify and diagnose problems with equipment before they become safety hazards.

Safety leader

Safety is at the core of our operations. Our safety record for 2016 was the best in our history and we believe significantly better than our industry peer group, based on data provided by reports of the U.S. Bureau of Labor Statistics from 2011 through 2016. For the past three years, we believe our total recordable incident rate was less than half of the industry average. During the first quarter of 2017, we reached a milestone of over 10 million man-hours without a lost time incident. Many of our customers impose minimum safety requirements on their suppliers of hydraulic fracturing services, and some of our competitors are not permitted to bid on work for certain customers because they do not meet those customers’ minimum safety requirements. Because safety is important to our customers, our safety score helps our commercial team to win business from our customers. Our safety focus is also a morale benefit for our crews, which enhances our employee retention rates. Finally, we believe that continually searching for ways to make our operations safer is the right thing to do for our employees and our customers.

Experienced management and operating team

During the downturn, our management team focused on reducing costs, increasing operating efficiency and differentiating ourselves through innovation. The team has an extensive and diverse skill set, with an average of over 23 years of professional experience. Our operational and commercial executives have a deep understanding of unconventional resource formations, with an average of approximately 31 years of oil and natural gas industry experience. In addition, as a result of our pure-play focus on hydraulic fracturing and dedicated fleet strategy, our operations teams have extensive knowledge of the geographies in which we operate as well as the technical specifications and other requirements of our customers. We believe this knowledge and experience allows us to service a variety of E&P companies across different basins efficiently and safely.

Our Strategy

Our primary business objective is to be the largest pure-play provider of hydraulic fracturing services within U.S. unconventional resource basins. We intend to achieve this objective through the following strategies:

Capitalize on expected recovery and demand for our services

As demand for oilfield services in the United States recovers, the hydraulic fracturing sector is expected to grow significantly. We believe that the cost per barrel of oil from unconventional onshore production is one of the lowest in the United States, and, as a result, E&P capital has shifted towards this type of production. Industry reports have forecasted that the number of horizontal wells drilled in the United States will increase at a compound annual growth rate, or CAGR, of 20.7% from 2016 through 2020. In addition, the sand utilized in the completion of a horizontal well has more than doubled since 2014 as operators continue to innovate to find the optimal job design. As one of the largest hydraulic fracturing service providers in North America, we believe we are well positioned to capitalize on the continued increase in the onshore oil and natural gas exploration and production market.

We have 1.6 million total hydraulic horsepower across 32 total fleets, with 27 fleets active as of December 31, 2017. A surge in demand for our services led us to reactivate 10 fleets since the beginning of 2017. We are in the process of activating additional fleets based on continued customer interest, and we believe all of this equipment can be returned to service within nine months, if market conditions require. We estimate the average cost to reactivate our inactive fleets to be approximately $6.9 million per fleet, which includes capital expenditures, repairs charged as operating expenses, labor costs and other operating expenses.

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Deepen and expand relationships with customers that value our completions efficiency

We service our customers primarily with dedicated fleets and 24-hour operations. We dedicate one or more of our fleets exclusively to the customer for a period of time, allowing for those fleets to be integrated into the customer’s drilling and completion schedule. As a result, we are able to achieve higher levels of utilization, as measured by the number of days each fleet is working per month, which increases our profitability. In addition, we operate our fleets on a 24-hour basis, allowing us to complete our services more efficiently with the least amount of downtime. Accordingly, we seek to partner with customers that have a large number of wells needing completion and that value efficiency in the performance of our service. Specifically, we target customers whose completions activity typically involves minimal downtime between stages, a high number of stages per well, multiple wells per pad and a short distance from one well pad site to the next. This strategy aligns with the strategy of many of our customers, who are trying to achieve a manufacturing-style model of drilling and completing wells in a sequential pattern to maximize effective acreage. We plan to leverage this strategy to expand our relationships with our existing customers as we continue to attract new customers.

Capitalize on our uniform fleet, leading scale and significant basin diversity to provide superior performance with reduced operating costs

We primarily serve large independent E&P companies that specialize in unconventional oil and natural gas resources in North America. Because we operate for customers with significant scale in each of our operating basins, we have the diversity to react to and benefit from positive activity trends in any basin with a balanced exposure to oil and natural gas. Our uniform fleet allows us to cost-effectively redeploy equipment and fleets among existing operating basins to capture the best pricing and activity trends. The uniform fleet is easier to operate and maintain, resulting in reduced downtime as well as lower training costs and inventory stocking requirements. Our geographic breadth also provides us with opportunities to capitalize on customer relationships in one basin in order to win business in other basins in which the customer operates. We intend to leverage our scale, standardized equipment and cost structure to gain market share and win new business.

Rapidly adopt new technologies in a capital efficient manner

Our large scale and culture of innovation allow us to take advantage of leading technological solutions. We have been a fast adopter of new technologies focused on: increasing fracturing effectiveness for our customers, reducing the operating costs of our equipment and enhancing the HSE conditions at our well sites. We help customers monitor and modify fracturing fluids and designs through our fluid research and development operations that we conduct through a strategic partnership with a third-party technology center that utilizes key employees who were previously affiliated with our Company. In June 2017, we renewed our services agreement with this third-party technology center for a one-year term, with an option for us to renew for additional one-year terms. This partnership allows us to work closely with our customers to rapidly adopt and integrate next-generation fluid breakthroughs, such as our NuFlo® 1000 fracturing fluid diverter, into our product offerings.

Recent examples of initiatives aimed at reducing our operating costs include: vibration sensors with predictive maintenance analytics on our heavy equipment; stainless steel fluid-ends with a longer useful life; high-definition cameras to remotely monitor the performance of our equipment; and adoption of hardened alloys and lubricant blends for our consumables. Recent examples of initiatives aimed at improving our HSE conditions include: dual fuel engines that can run on both natural gas and diesel fuel; electronic pressure relief systems; spill prevention and containment solutions; dust control mitigation; electronic logging devices; and leading containerized proppant delivery solutions.

Reduce debt and maintain a more conservative capital structure

To improve our financial flexibility, we entered into a $250.0 million asset-based revolving credit facility on February 22, 2018. Our focus will be on the continued prudent management of our capital structure. We believe this focus creates potential for significant operating leverage and strong free cash flow generation during an industry upcycle. As a result, we believe we should be able to not only make the investments necessary to remain a market leader in hydraulic fracturing, but also to continue to strengthen our balance sheet. If we are able to sufficiently reduce our indebtedness and continue to generate cash flow from operations, we expect to return value to shareholders, including by means of cash returns, accretive acquisitions that fit our model and footprint, or the construction of new fleets depending on our business outlook. See “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Dividends” in Item 5 of this annual report and “Risk Factors — Risks Relating to Our Indebtedness” in Item 1A of this annual report for more information.

Customers

The customers we serve are primarily large, independent E&P companies that specialize in unconventional oil and natural gas resources in North America. The following table shows the customers that represented more than 10% of our total revenue during

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the years ended December 31, 2015, 2016 and 2017. No customer accounted for more than 10% of our total revenue during the year ended December 31, 2017. The loss of any of our largest existing customers could have a material adverse effect on our results of operations.

	Year Ended December 31,
	2015		2016		2017
EP Energy Corporation	*		11	%	*
Chesapeake Energy Corporation	*		*		*
EQT Production Company	12	%	12	%	*
Vine Oil and Gas, L.P.	*		10	%	*
Range Resources Corporation	13	%	*		*
Newfield Exploration	*		18	%	*
Murphy Oil Corporation	11	%	*		*

*Less than 10%.

Suppliers

We purchase some of the parts that we use in the refurbishment and repair of our heavy equipment, such as hydraulic fracturing units and blenders, and in the refurbishment, repair and manufacturing of certain major replacement components of our heavy equipment such as fluid-ends, power-ends, engines, transmissions, radiators and trailers. We also purchase the proppants and chemicals we use in our operations and the diesel fuel for our equipment from a variety of suppliers throughout the United States. We have long-term supply agreements with four vendors to supply a significant portion of the proppant used in our operations, ranging from two to eight years. These are take-or-pay agreements with minimum unconditional purchase obligations. These minimum purchase obligations would change based upon the vendors’ ability to supply the minimum requirements. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis at competitive prices. In the past, we have experienced some delays in obtaining these materials during periods of high demand. We do not currently expect significant interruptions in the supply of these materials. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, there can be no assurance that there will be no price or supply issues over the long-term.

Competition

The market in which we operate is highly competitive and highly fragmented. Our competition includes multi-national oilfield service companies as well as regional competitors. Our major multi-national competitors are Halliburton Company and Schlumberger Limited, each of which has significantly greater financial resources than we do. Our major domestic competitors are RPC, Inc., Superior Energy Services, ProPetro Holding Corp., Patterson-UTI Energy, Inc., BJ Services, Inc., Liberty Oilfield Services Inc. and Keane Group, Inc. Certain of these competitors are large, multi-national and major domestic businesses that provide a number of oilfield services and products in addition to hydraulic fracturing. We also face competition from smaller regional service providers in some of the geographies in which we operate.

Competition in our industry is based on a number of factors, including price, service quality, safety, and in some cases, breadth of products. We believe we consistently deliver exceptional service quality, based in part on the durability of our equipment. Our durable equipment reduces downtime due to equipment failure and allows our customers to avoid costs associated with delays in completing their wells. By being able to meet the most demanding pressure and flow rate requirements, our equipment also enables us to operate efficiently in challenging geological environments in which some of our competitors cannot operate effectively.

Cyclical Nature of Industry

We operate in a highly cyclical industry driven mainly by the level of horizontal drilling activity by E&P companies in unconventional oil and natural gas reservoirs in North America, which in turn depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. A critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. Demand for oil and natural gas is subject to large and rapid fluctuations. These fluctuations are driven by commodity demand in the industry and corresponding price increases. When oil and natural gas prices increase, producers generally increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. However, increased capital expenditures also ultimately result in greater production, which historically, has resulted in increased supplies and reduced prices that, in turn, tend to reduce demand for oilfield services such as

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hydraulic fracturing services. For these reasons, our results of operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort period-to-period comparisons of our results of operations.

Seasonality

Seasonality has not significantly affected our overall operations. However, toward the end of some years, we experience slower activity in our pressure pumping operations in connection with the holidays and as customers’ capital expenditure budgets are depleted. Occasionally, our operations have been negatively impacted by severe weather conditions.

Employees

At December 31, 2017, we had approximately 2,400 employees. Our employees are not covered by collective bargaining agreements, nor are they members of labor unions. We consider our relationship with our employees to be good.

Insurance

Our operations are subject to hazards inherent in the oil and natural gas industry, including accidents, blowouts, explosions, fires, oil spills and hazardous materials spills. These conditions can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment and wildlife and interruption or suspension of operations, among other adverse effects. If a serious accident were to occur at a location where our equipment and services are being used, it could result in our being named as a defendant to a lawsuit asserting significant claims.

Despite our high safety standards, we from time to time have suffered accidents in the past and we anticipate that we could experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, as well as our relationships with customers, employees and regulatory agencies. 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 adverse effects on our financial condition and results of operations.

We carry a variety of insurance coverages for our operations, and we are partially self-insured for certain claims, in types and amounts that we believe to be customary and reasonable for our industry. These coverages and retentions address certain risks relating to commercial general liability, workers’ compensation, business auto, property and equipment, directors and officers, environment, pollution and other risks. Although we maintain insurance coverage of types and amounts that we believe to be customary in our 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.

Environmental Regulation

Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of that person. Strict adherence with these regulatory requirements increases our cost of doing business and consequently affects our profitability. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our business, financial condition and results of operations.

Hydraulic Fracturing Activities. Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report, entitled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States,” on the potential impacts of hydraulic fracturing on drinking water resources. The report states that the EPA found scientific evidence that hydraulic fracturing activities can impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: 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 report does not make any policy

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recommendations. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states, counties and municipalities are closely examining water-use issues, such as permit and disposal options for processed water. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from drilling wells. See “Risk Factors—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” in Item 1A of this annual report.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, referred to as “CERCLA” or the “Superfund law,” and comparable state laws generally impose liability, without regard to fault or legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of hazardous or other state-regulated substances 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 substances at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. 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 hazardous substances released into the environment.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations issued thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States, as well as state waters. On December 13, 2016, the EPA released a final report which identified discharge of inadequately treated hydraulic fracturing wastewater to surface water resources as having potential to impact drinking water resources. 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. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff, which require covered facilities to obtain permits.

These laws and regulations also prohibit certain other activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers, which we refer to as the Corps. In September 2015, a new rule became effective which was issued by the EPA and the Corps defining the scope of the jurisdiction of the EPA and the Corps over wetlands and other waters. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act’s programs, and implementation of the rule has been stayed pending resolution of the court challenge. In November 2017, the EPA and the Corps published a new proposed rule defining the scope of jurisdiction and adding an applicability date of two years after the date of a final rule under the proposed rulemaking effort. Also, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters. Noncompliance with these requirements may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations.

Waste Handling. Wastes from certain of our operations (such as equipment maintenance and past chemical development, blending, and distribution operations) are subject to the federal Resource Conservation and Recovery Act of 1976 (“RCRA”), and comparable state statutes and regulations promulgated thereunder, which impose 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 oil 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. In the EPA’s 2016 final report on the impacts from hydraulic fracturing on drinking water resources, the EPA identified disposal or storage of hydraulic fracturing wastewater in unlined pits as resulting in contamination of groundwater resources.

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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 categorize some non-hazardous wastes as hazardous for future regulation. Legislation has been proposed from time to time in Congress to re-categorize 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 the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

From time to time, releases of materials or wastes have occurred at locations we own, owned previously or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA, the federal Clean Water Act, and analogous state laws. Under these laws or other laws and regulations, we have been and may be required to remove or remediate these materials or wastes and make expenditures associated with personal injury or property damage. At this time, with respect to any properties where materials or wastes may have been released, but of which we have not been made aware, it is not possible to estimate the potential costs that may arise from unknown, latent liability risks.

Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants from specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. We are required to obtain federal and state permits in connection with some activities under applicable laws. These permits impose certain conditions and restrictions on our operations, some of which require significant expenditures for compliance. Changes in these requirements, or in the permits we operate under, could increase our costs or limit operations.

Additionally, the EPA’s Tier IV regulations apply to certain off-road diesel engines used by us to power equipment in the field. Under these regulations, we are required to retrofit or retire certain engines and we are limited in the number of non-compliant off-road diesel engines we can purchase. Tier IV engines are costlier and not widely available. Until Tier IV-compliant engines that meet our needs are more widely available, these regulations could limit our ability to acquire a sufficient number of diesel engines to expand our fleet and to replace existing engines as they are taken out of service.

Other Environmental Considerations. E&P activities on federal lands may be subject to the National Environmental Policy Act, which we refer to as NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. E&P activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Where takings of or harm to species or damages to jurisdictional streams or wetlands habitat or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and natural gas exploration activities or seek damages for harm to species, habitat, or natural resources resulting from filling of jurisdictional streams or wetlands or construction or releases of oil, wastes, hazardous substances or other regulated materials.

BLM has established regulations to govern hydraulic fracturing on federal and Indian lands. The 2015 Hydraulic Fracturing on Federal and Indian Lands Rule (the “Federal and Indian Lands Rule”) imposes drilling and construction requirements for operations on federal or Indian lands including management requirements for surface operations and public disclosures of chemicals used in the hydraulic fracturing fluids. In June 2016, the U.S. District Court of Wyoming ruled that the BLM lacked statutory authority to promulgate the Federal and Indian Lands Rule. On July 25, 2017, BLM published a Notice in the Federal Register proposing to rescind the Federal and Indian Lands Rule. On September 21, 2017, the Tenth Circuit dismissed as moot the appeal challenging the rule and vacated the June 2016 U.S. District Court of Wyoming decision that invalidated the Federal and Indian Lands Rule. On December 29, 2017, BLM published a rescission of these regulations. BLM also promulgated the 2016 Methane and Waste Reduction Rule to reduce waste of natural gas supplies and reduce air pollution, including greenhouse gases, for oil and natural gas produced on federal and Indian lands. Various states have filed for a petition for review of the Methane and Waste Reduction Rule. On December 8, 2017, BLM published a final rule delay until January 2019 for certain requirements of the rule that had not yet gone into effect pending judicial review of the rule. A coalition of environmental groups has filed suit challenging the delay. Imposition of these rules could increase our costs or limit operations.

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The Toxic Substances Control Act (“TSCA”), requires manufacturers of new chemical substances to provide specific information to the Agency for review prior to manufacturing chemicals or introducing them into commerce. EPA has permitted manufacture of new chemical nanoscale materials through the use of consent orders or Significant New Use Rules under TSCA. The Agency has also allowed the manufacture of new chemical nanoscale materials under the terms of certain regulatory exemptions where exposures were controlled to protect against unreasonable risks. On May 19, 2014, the EPA published an Advanced Notice of Proposed Rulemaking to obtain data on hydraulic fracturing chemical substances and mixtures. The EPA projects publication of a notice of proposed rulemaking in June of 2018. Any changes in TSCA regulations could increase our capital expenditures and operating expenses.

Climate Change. In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. The EPA later adopted two sets of related rules, one of which regulates emissions of greenhouse gases from motor vehicles and the other of which regulates emissions from certain large stationary sources of emissions. The motor vehicle rule, which became effective in July 2010, limits emissions from motor vehicles. The EPA adopted the stationary source rule, which we refer to as the tailoring rule, in May 2010, and it became effective January 2011. The tailoring rule established new emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration “(PSD”), and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their greenhouse gas emissions. However, the Court ruled that the EPA may require installation of best available control technology for greenhouse gas emissions at sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two memoranda providing guidance on greenhouse gas permitting requirements in response to the Supreme Court’s decision. In its preliminary guidance, the EPA stated that it would undertake a rulemaking action to rescind any PSD permits issued under the portions of the tailoring rule that were vacated by the Court. In the interim, the EPA issued a narrowly crafted “no action assurance” indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and conditions relating to greenhouse gases in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit. On April 30, 2015, the EPA issued a final rule allowing permitting authorities to rescind PSD permits issued under the invalid regulations. In October 2015, the EPA amended the greenhouse gas reporting rule to add the reporting of emissions from oil wells using hydraulic fracturing. Because of this continued regulatory focus, future emission regulations of the oil and natural gas industry remain a possibility, which could increase the cost of our operations.

In addition, the U.S. Congress occasionally attempts to adopt legislation to reduce emissions of greenhouse gases, and almost one-half of the states have taken legal measures to reduce emissions primarily through the planned development of greenhouse gas emission inventories or regional cap and trade programs. Although the U.S. Congress has not yet adopted such legislation, it may do so in the future. Several states continue to pursue related regulations as well. 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, which came into force on November 4, 2016, establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. Although the Trump Administration has withdrawn the United States from the Paris Agreement, many state and local officials have publicly stated they intend to abide by the terms of the Paris Agreement. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry which could have a material adverse effect on future demand for our services. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our customers’ business and consequently our own.

In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal or state common law. As a result, private individuals may seek to enforce environmental laws and regulations and could allege personal injury or property damages, which could increase our operating costs.

NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials associated with oil and natural gas deposits and, accordingly may result in the generation of wastes and other materials containing naturally occurring radioactive materials (“NORM”). NORM exhibiting levels of naturally occurring 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. Because certain of the properties presently or previously owned, operated or occupied by us may have been used for oil and natural gas production operations, it is possible that we may incur costs or liabilities associated with NORM.

Pollution Risk Management. We seek to minimize the possibility of a pollution event through equipment and job design, as well as through employee training. We also maintain a pollution risk management program if a pollution event occurs. This program

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includes an internal emergency response plan that provides specific procedures for our employees to follow in the event of a chemical release or spill. In addition, we have contracted with several third-party emergency responders in our various operating areas that are available on a 24-hour basis to handle the remediation and clean-up of any chemical release or spill. We carry insurance designed to respond to foreseeable environmental exposures. This insurance portfolio has been structured in an effort to address incidents that result in bodily injury or property damage and any ensuing clean up needed at our owned facilities as a result of the mobilization and utilization of our fleet, as well as any claims resulting from our operations.

We also seek to manage environmental liability risks through provisions in our contracts with our customers that allocate risks relating to surface activities associated with the fracturing process, other than water disposal, to us and risks relating to “downhole” liabilities to our customers. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well as waste water. The customers remove the water from the well using a controlled flow-back process, and we are not involved in that process or the disposal of the fluid. Our contracts generally require our customers to indemnify us against pollution and environmental damages originating below the surface of the ground or arising out of water disposal, or otherwise caused by the customer, other contractors or other third parties. In turn, we indemnify our customers for pollution and environmental damages originating at or above the surface caused solely by us. We seek to maintain consistent risk-allocation and indemnification provisions in our customer agreements to the greatest extent possible. Some of our contracts, however, contain less explicit indemnification provisions, which typically provide that each party will indemnify the other against liabilities to third parties resulting from the indemnifying party’s actions, except to the extent such liability results from the indemnified party’s gross negligence, willful misconduct or intentional act.

Safety and Health Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act, which is administered and enforced by OSHA, and comparable state laws that 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. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances. OSHA continues to evaluate worker safety and to propose new regulations, such as but not limited to, the new rule regarding respirable silica sand. Although it is not possible to estimate the financial and compliance impact of the new respirable silica sand rule or any other proposed rule, the imposition of more stringent requirements could have a material adverse effect on our business, financial condition and results of operations.

Intellectual Property Rights

Our research and development efforts are focused on providing specific solutions to the challenges our customers face when fracturing and stimulating wells. In addition to the design and manufacture of innovative equipment, we have also developed proprietary blends of chemicals that we use in connection with our hydraulic fracturing services. We have four U.S. patents, one patent in Canada and one patent in Mexico, and have filed one patent application in the U.S., relating to fracturing methods, the technology used in fluid ends, hydraulic pumps and other equipment. We have also filed two applications with the Patent Cooperation Treaty, thereby preserving our right to seek patent protection in countries that are a party to the treaty.

We believe the information regarding our customer and supplier relationships are also valuable proprietary assets. We have registered trademarks for various names under which our entities conduct business. Except for the foregoing, we do not own or license any patents, trademarks or other intellectual property that we believe to be material to the success of our business.

Item 1A. Risk Factors

Our investors should carefully consider the following risks and other information in this annual report in evaluating us and our common stock. Any of the following risks, as well as additional risks and uncertainties not currently known to us or that we currently deem immaterial, could materially and adversely affect our business, financial condition or results of operations, and could, in turn, impact the trading price of our common stock.

Risks Relating to Our Business

Our business depends on domestic spending by the onshore oil and natural gas industry, which is cyclical and significantly declined in 2015 and 2016.

Our business is cyclical and depends on the willingness of our customers to make operating and capital expenditures to explore for, develop and produce oil and natural gas in the United States. The willingness of our customers to undertake these

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activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as:

· prices, and expectations about future prices, for oil and natural gas;

· domestic and foreign supply of, and demand for, oil and natural gas and related products;

· the level of global and domestic oil and natural gas inventories;

· the supply of and demand for hydraulic fracturing and other oilfield services and equipment in the United States;

· the cost of exploring for, developing, producing and delivering oil and natural gas;

· available pipeline, storage and other transportation capacity;

· lead times associated with acquiring equipment and products and availability of qualified personnel;

· the discovery rates of new oil and natural gas reserves;

· federal, state and local regulation of hydraulic fracturing and other oilfield service activities, as well as E&P activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;

· the availability of water resources, suitable proppant and chemicals in sufficient quantities for use in hydraulic fracturing fluids;

· geopolitical developments and political instability in oil and natural gas producing countries;

· actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

· advances in exploration, development and production technologies or in technologies affecting energy consumption;

· the price and availability of alternative fuels and energy sources;

· weather conditions and natural disasters;

· uncertainty in capital and commodities markets and the ability of oil and natural gas producers to raise equity capital and debt financing; and

· U.S. federal, state and local and non-U.S. governmental regulations and taxes.

Volatility or weakness in oil and natural gas prices (or the perception that oil and natural gas prices will decrease or remain depressed) generally leads to decreased spending by our customers, which in turn negatively impacts drilling, completion and production activity. In particular, the demand for new or existing drilling, completion and production work is driven by available investment capital for such work. When these capital investments decline, our customers’ demand for our services declines. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be risk averse when commodity prices are low or volatile, we typically experience a more rapid decline in demand for our services compared with demand for other types of energy services. Any negative impact on the spending patterns of our customers may cause lower pricing and utilization for our services, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Oil and natural gas prices declined significantly in 2015 and 2016 and remain volatile, which has adversely affected, and may continue to adversely affect, our financial condition, results of operations and cash flows.

The demand for our services depends on the level of spending by oil and natural gas companies for drilling, completion and production activities, which are affected by short-term and long-term trends in oil and natural gas prices, including current and anticipated oil and natural gas prices. Oil and natural gas prices, as well as the level of drilling, completion and production activities, historically have been extremely volatile and are expected to continue to be highly volatile. For example, oil prices declined significantly in 2015 and 2016, with WTI crude oil spot prices declining from a monthly average of $105.79 per barrel in June 2014 to $26.14 per barrel in February 2016. The spot price per barrel as of December 29, 2017 was $60.42. In line with this sustained volatility in oil and natural gas prices, we experienced a significant decline in pressure pumping activity levels across our customer base. The volatile oil and natural gas prices adversely affected, and could continue to adversely affect, our financial condition, results of operations and cash flows.

Our customers may not be able to maintain or increase their reserve levels going forward.

In addition to the impact of future oil and natural gas prices on our financial performance over time, our ability to grow future revenues and increase profitability will depend largely upon our customers’ ability to find, develop or acquire additional shale oil and

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natural gas reserves that are economically recoverable to replace the reserves they produce. Hydraulic fractured wells are generally more short-lived than conventional wells. Our customers own or have access to a finite amount of shale oil and natural gas reserves in the United States that will be depleted over time. The production rate from shale oil and natural gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. If our customers are unable to replace the shale oil reserves they own or have access to at the rate they produce such reserves, their proved reserves and production will decline over time. Reductions in production levels by our customers over time may reduce the future demand for our services and adversely affect our business, financial condition, results of operations and cash flows.

Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.

A prolonged economic slowdown or recession in the United States, adverse events relating to the energy industry or regional, national and global economic conditions and factors, particularly a slowdown in the E&P industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased exploration and development spending by our customers, decreased demand for oil and natural gas and decreased prices for oil and natural gas.

Competition in our industry intensifies during industry downturns, and we may not be able to provide services that meet the specific needs of our customers at competitive prices.

The markets in which we operate are generally highly competitive and have relatively few barriers to entry. The principal competitive factors in our markets are price, service quality, safety, and in some cases, breadth of products. 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. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts 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 during the recent downturn, we had to lower the prices for our services. In future downturns, 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.

Pressure on pricing for our services resulting from the recent industry downturn impacted our ability to maintain utilization and pricing for our services or implement price increases, which may also be impacted in future downturns. During any future periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results of operations. Also, we may not be able to successfully increase prices without adversely affecting our utilization levels. The inability to maintain our utilization and pricing levels, or to increase our prices as costs increase, could have a material adverse effect on our business, financial condition and results of operations.

In addition, some E&P companies have begun performing hydraulic fracturing on their wells using their own 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.

We are dependent on a few customers operating in a single industry. The loss of one or more significant customers could adversely affect our financial condition and results of operations.

Our customers are engaged in the E&P business in the United States. Historically, we have been dependent upon a few customers for a significant portion of our revenues. For the years ended December 31, 2016 and December 31, 2017, our four largest customers generated approximately 52% and 32%, respectively, of our total revenue. In fiscal years 2015 and 2014, our four largest customers generated approximately 44% and 45%, respectively, of our total revenue. For a discussion of our customers that make up 10% or more of our revenues, see “Business—Customers” in Item 1 of this annual report.

Our business, financial condition and results of operations could be materially adversely affected if one or more of our significant customers ceases to engage us for our services on favorable terms or at all or fails to pay or delays in paying us significant amounts of our outstanding receivables. Although we do have contracts for multiple projects with certain of our customers, most of our services are provided on a project-by-project basis.

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Additionally, the E&P industry is characterized by frequent consolidation activity. Changes in ownership of our customers may result in the loss of, or reduction in, business from those customers, which could materially and adversely affect our financial condition.

We extend credit to our customers, which presents a risk of nonpayment of our accounts receivable.

We extend credit to all our customers. During the recent industry downturn, many of our customers experienced the same financial and operational challenges that we did, and some of our customers filed for bankruptcy protection. Given the cyclical nature of the E&P industry, we, as well as our customers, may experience similar challenges in the future. As a result, we may have difficulty collecting outstanding accounts receivable from, or experience longer collection cycles with, some of our customers, which could have an adverse effect on our financial condition and cash flows.

Decreased demand for proppant has adversely affected, and could continue to adversely affect, our commitments under supply agreements.

We have purchase commitments with certain vendors to supply the proppant used in our operations. Some of these agreements are take-or-pay arrangements with minimum purchase obligations. During the industry downturn, our minimum contractual commitments exceeded the amount of proppant needed in our operations. As a result, we made minimum payments for proppant that we were unable to use. Furthermore, some of our customers have bought and in the future may buy proppant directly from vendors, reducing our need for proppant. If market conditions do not continue to improve, or our customers buy proppant directly from vendors, we may be required to make minimum payments in future periods, which may adversely affect our results of operations, liquidity and cash flows.

We may be unable to employ a sufficient number of key employees, technical personnel and other skilled or qualified workers.

The delivery of our services and products requires personnel with specialized skills and experience who can perform physically demanding work. As a result of the volatility in the energy service industry and the demanding nature of the work, workers may choose to pursue employment with our competitors or in fields that offer a more desirable work environment. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to further expand our operations according to geographic demand for our services depends in part on our ability to relocate or increase the size of our skilled labor force. The demand for skilled workers in our areas of operations can be high, the supply may be limited and we may be unable to relocate our employees from areas of lower utilization to areas of higher demand. 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. Furthermore, a significant decrease in the wages paid by us or our competitors as a result of reduced industry demand could result in a reduction of the available skilled labor force, and there is no assurance that the availability of skilled labor will improve following a subsequent increase in demand for our services or an increase in wage rates. If any of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

We depend heavily on the efforts of executive officers, managers and other key employees to manage our operations. The unexpected loss or unavailability of key members of management or technical personnel may have a material adverse effect on our business, financial condition, prospects or results of operations.

Our operations are subject to inherent risks, including operational hazards. These risks may not be fully covered under our insurance policies.

Our operations are subject to hazards inherent in the oil and natural gas industry, such as accidents, blowouts, explosions, craters, fires and oil spills. These hazards may lead to property damage, personal injury, death or the discharge of hazardous materials into the environment. The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations.

As is customary in our industry, our service contracts generally provide that we will indemnify and hold harmless our customers from any claims arising from personal injury or death of our employees, damage to or loss of our equipment, and pollution emanating from our equipment and services. Similarly, our customers agree to indemnify and hold us harmless from any claims arising from personal injury or death of their employees, damage to or loss of their equipment, and pollution caused from their equipment or the well reservoir. Our indemnification arrangements may not protect us in every case. In addition, our indemnification rights may not fully protect us if the customer is insolvent or becomes bankrupt, does not maintain adequate insurance or otherwise does not possess sufficient resources to indemnify us. Furthermore, our indemnification rights may be held unenforceable in some

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jurisdictions. Our inability to fully realize the benefits of our contractual indemnification protections could result in significant liabilities and could adversely affect our financial condition, results of operations and cash flows.

We maintain customary insurance coverage against these types of hazards. We are self-insured up to retention limits with regard to, among other things, workers’ compensation and general liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate.

We are subject to laws and regulations regarding issues of health, safety, and protection of the environment, under which we may become liable for penalties, damages, or costs of remediation.

Our operations are subject to stringent laws and regulations relating to protection of natural resources, clean air, drinking water, wetlands, endangered species, greenhouse gases, nonattainment areas, the environment, health and safety, chemical use and storage, waste management, and transportation of hazardous and non-hazardous materials. These laws and regulations subject us to risks of environmental liability, including leakage from an operator’s casing during our operations or accidental spills or releases onto or into surface or subsurface soils, surface water, groundwater or ambient air.

Some environmental laws and regulations may impose strict liability, joint and several liability or both. Strict liability means that we could be exposed to liability as a result of our conduct that was lawful at the time it occurred, or the conduct of or conditions caused by third parties without regard to whether we caused or contributed to the conditions. Additionally, environmental concerns, including air and drinking water contamination and seismic activity, have prompted investigations that could lead to the enactment of regulations that potentially could have a material adverse impact on our business. Sanctions for noncompliance with environmental laws and regulations could result in fines and penalties (administrative, civil or criminal), revocations of permits, expenditures for remediation, and issuance of corrective action orders, and actions arising under these laws and regulations could result in liability for property damage, exposure to waste and other hazardous materials, nuisance or personal injuries. Such claims or sanctions could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, and results of operations.

Changes in laws and regulations could prohibit, restrict or limit our operations, increase our operating costs, adversely affect our results or result in the disclosure of proprietary information resulting in competitive harm.

Various legislative and regulatory initiatives have been undertaken that could result in additional requirements or restrictions being imposed on our operations. Legislation and/or regulations are being considered at the federal, state and local levels that could impose chemical disclosure requirements (such as restrictions on the use of certain types of chemicals or prohibitions on hydraulic fracturing operations in certain areas) and prior approval requirements. If they become effective, these regulations would establish additional levels of regulation that could lead to operational delays and increased operating costs. Disclosure of our proprietary chemical information to third parties or to the public, even if inadvertent, could diminish the value of our trade secrets and could result in competitive harm to us, which could have an adverse impact on our financial condition and results of operations.

Additionally, some jurisdictions are or have considered zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations, and are closely examining permit and disposal options for processed water, which if imposed could have a material adverse impact on our operating costs. Moreover, any moratorium or increased regulation of our raw materials vendors, such as our proppant suppliers, could increase the cost of those materials and adversely affect the results of our operations.

We are also subject to various transportation regulations that include certain permit requirements of highway and vehicle and hazardous material safety authorities. These regulations govern such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. As these regulations develop and any new regulations are proposed, we have experienced and may continue to experience an increase in related costs. We receive a portion of the proppant used in our operations by rail. Any delay or failure in rail services due to changes in transportation regulations, work stoppages or labor strikes, could adversely affect the availability of proppant. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations.

We continue to assess the impact of the recently enacted Tax Cuts and Jobs Act (the “new tax law”) as well as any future regulations implementing the new tax law and any interpretations of the new tax law. The effect of those regulations and

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interpretations, as well as any additional tax reform legislation in the United States or elsewhere, could adversely affect our business and financial condition.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Our business is dependent on our ability to conduct hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing 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, or proppants, 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, on May 9, 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. The EPA projects publishing a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism—regulatory, voluntary or a combination of both—to collect data on hydraulic fracturing chemical substances and mixtures. On June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plans. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities and the environmental impacts of discharges from CWT facilities. The EPA entered a consent decree which requires the agency to determine whether to revise the Resource Conservation and Recovery Act Subtitle D rules for oil and gas waste by March 5, 2019. Furthermore, legislation to amend the Safe Drinking Water Act (“SDWA”), 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, were proposed in recent sessions of Congress. Additionally, the Bureau of Land Management (“BLM”), has established regulations imposing drilling and construction requirements for operations on federal or Indian lands including management requirements for surface operations and public disclosures of chemicals used in the hydraulic fracturing fluids. However, on December 29, 2017, BLM published a rescission of these regulations. Future imposition of these or similar regulations could cause us or our customers to incur substantial compliance costs and any failure to comply could have a material adverse effect on our financial condition or results of operations.

On May 12, 2016, the EPA amended the New Source Performance Standards under the federal Clean Air Act to impose new standards for methane and volatile organic compounds (“VOCs”), emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. On the same day, the EPA finalized a plan to implement its minor new source review program in Indian country for oil and natural gas production, and it issued for public comment an information request that will require companies to provide extensive information instrumental for the development of regulations to reduce methane emissions from existing oil and natural gas sources. The EPA announced intentions to publish reconsidered proposed New Source Performance Standards by August of 2018 with a final revised rule in September 2019.

In November 2016, BLM promulgated regulations aimed at curbing air pollution, including greenhouse gases, for oil and natural gas produced on federal and Indian lands. Various states have filed for a petition for review of these regulations. On June 15, 2017, BLM published a Notice in the Federal Register proposing to postpone compliance dates for provisions of the rule that had not yet gone into effect pending judicial review of the Rule. On October 4, 2017, the U.S. District Court for the Northern District of California invalidated BLM’s June 15, 2017 proposed postponement of compliance deadlines. On December 8, 2017, BLM promulgated a final rule delay to temporarily suspend or delay certain requirements until January 17, 2019. A coalition of environmental groups has filed suit challenging the delay. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

There are certain governmental reviews either underway or being proposed that focus on the environmental aspects of hydraulic fracturing practices. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The EPA continues to evaluate the potential impacts of hydraulic fracturing on drinking water resources and the induced seismic activity from disposal wells and has recommended strategies for managing and minimizing the potential for significant injection-induced seismic events. For example, in December 2016, the EPA released its final report, entitled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States,” on the potential impacts of hydraulic fracturing on drinking water resources. The report states that the EPA found scientific evidence that hydraulic fracturing activities can impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids,

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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. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly to perform fracturing and increase the costs of compliance and doing business for our customers. Furthermore, the EPA plans to continue an enforcement initiative to ensure energy extraction activities comply with federal laws.

In addition to bans on hydraulic fracturing activities in Maryland, New York and Vermont, several states, including Texas and Ohio, as well as regional authorities like the Delaware River Basin Commission, 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. Any increased regulation of hydraulic fracturing, in these or other states, could reduce the demand for our services and materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our customers’ fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause us or our customers to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Existing or future laws and regulations related to greenhouse gases and climate change could have a negative impact on our business and may result in additional compliance obligations with respect to the release, capture, and use of carbon dioxide that could have a material adverse effect on our business, results of operations, and financial condition.

Changes in environmental requirements related to greenhouse gases and climate change may negatively impact demand for our services. For example, oil and natural gas exploration and production may decline as a result of environmental requirements, including land use policies responsive to environmental concerns. Local, state, and federal agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which we conduct business. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws and regulations related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration, and use of carbon dioxide or other gases that could have a material adverse effect on our business, results of operations, and financial condition.

Delays in obtaining, or inability to obtain or renew, permits or authorizations by our customers for their operations or by us for our operations could impair our business.

In most states, our customers are required to obtain permits or authorizations from one or more governmental agencies or other third parties to perform drilling and completion activities, including hydraulic fracturing. Such permits or approvals are typically required by state agencies, but can also be required by federal and local governmental agencies or other third parties. The requirements for such permits or authorizations vary depending on the location where such drilling and completion activities will be conducted. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued and the conditions which may be imposed in connection with the granting of the permit. In some jurisdictions, such as New York State and within the jurisdiction of the Delaware River Basin Commission, certain regulatory authorities have delayed or suspended the issuance of permits or authorizations while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. In Texas, rural water districts have begun to impose restrictions on water use and may require permits for water used in drilling and completion activities. Permitting, authorization or renewal delays, the inability to obtain new permits or the revocation of current permits could cause a loss of revenue and potentially have a materially adverse effect on our business, financial condition, prospects or results of operations.

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We are also required to obtain federal, state, local and/or third-party permits and authorizations in some jurisdictions in connection with our wireline services. These permits, when required, impose certain conditions on our operations. Any changes in these requirements could have a material adverse effect on our financial condition, prospects and results of operations.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit our ability to operate in protected areas. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. Additionally, the designation of previously unprotected species as threatened or endangered in areas where we operate could result in increased costs arising from species protection measures. Restrictions on oil and natural gas operations to protect wildlife could reduce demand for our services.

Conservation measures 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.

There may be a reduction in demand for our future services due to competition from alternative energy sources.

Oil and natural gas competes with other sources of energy for consumer demand. There are significant governmental incentives and consumer pressures to increase the use of alternative energy sources in the United States and abroad. A number of automotive, industrial and power generation manufacturers are developing more fuel efficient engines, hybrid engines and alternative clean power systems using fuel cells or clean burning fuels. Greater use of these alternatives as a result of governmental incentives or regulations, technological advances, consumer demand, improved pricing or otherwise over time will reduce the demand for our products and services and adversely affect our business, financial condition, results of operations and cash flows going forward.

Limitations on construction of new natural gas pipelines or increases in federal or state regulation of natural gas pipelines could decrease demand for our services.

There has been increasing public controversy regarding construction of new natural gas pipelines and the stringency of current regulation of natural gas pipelines. Delays in construction of new pipelines or increased stringency of regulation of existing natural gas pipelines at either the state or federal level could reduce the demand for our services and materially and adversely affect our revenues and results of operations.

Our existing fleets require significant amounts of capital for maintenance, upgrades and refurbishment and any new fleets we acquire may require significant capital expenditures.

Our fleets require significant capital investment in maintenance, upgrades and refurbishment to maintain their effectiveness. While we manufacture many of the components necessary to maintain, upgrade and refurbish our fleets, labor costs have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs to upgrade any of our existing fleets or build any new fleets.

Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our existing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 were $79.1 million, $10.3 million and $64.0 million, respectively, in 2015, 2016 and 2017. Since 2015, we have financed capital expenditures primarily with funding from cash on hand. 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 properly maintaining our existing equipment or acquiring new

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equipment. Furthermore, 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 circumstance could put us at a competitive disadvantage or interfere with our growth plans. Furthermore, our actual capital expenditures for future years could exceed our capital expenditure budgets. 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.

A third party may claim we infringed upon its intellectual property rights, and we may be subjected to costly litigation.

Our operations, including equipment, manufacturing and fluid and chemical operations may unintentionally infringe upon the patents or trade secrets of a competitor or other company that uses proprietary components or processes in its operations, and that company may have legal recourse against our use of its protected information. If this were to happen, these claims could result in legal and other costs associated with litigation. If found to have infringed upon protected information, we may have to pay damages or make royalty payments in order to continue using that information, which could substantially increase the costs previously associated with certain products or services, or we may have to discontinue use of the information or product altogether. Any of these could materially and adversely affect our business, financial condition or results of operations.

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. Furthermore, we may face competitive pressure to implement or acquire certain new 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 implement new technologies before we can. We cannot be certain that we will be able to implement all new technologies or products on a timely basis or at an acceptable cost. Thus, limits on our ability to effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition or results of operations.

Loss or corruption of our information or a cyberattack on our computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer-based programs, including our well operations information and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, whether due to cyberattack or otherwise, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain activities. At the same time, cyberattacks 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 may become the target of cyberattacks or information security breaches. These could result in the unauthorized access, misuse, loss or destruction of our proprietary and other information or other disruption of our business operations. Any access or surveillance could remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. 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 any vulnerability to cyber incidents. Additionally, our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. Any additional costs could materially adversely affect our results of operations.

One or more of our directors may not reside in the United States, which may prevent investors from obtaining or enforcing judgments against them.

Because one or more of our directors may not reside in the United States, it may not be possible for investors to effect service of process within the United States on our non-U.S. resident directors, enforce judgments obtained in U.S. courts based on the civil liability provisions of the U.S. federal securities laws against our non-U.S. resident directors, enforce in foreign courts U.S. court judgments based on civil liability provisions of the U.S. federal securities laws against our non-U.S. resident directors, or bring an original action in foreign courts to enforce liabilities based on the U.S. federal securities laws against our non-U.S. resident directors.

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Risks Relating to Our Common Stock

Our three largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.

Before our initial public offering (the “IPO”) in February 2018, we were controlled by an investor group comprised mainly of Maju Investments (Mauritius) Pte Ltd (“Maju”), an indirect wholly owned subsidiary of Temasek Holdings (Private) Limited (“Temasek”), CHK Energy Holdings, Inc. (“Chesapeake”), a wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake Parent”), and Senja Capital Ltd (“Senja”), an investment company affiliated with RRJ Capital Limited (“RRJ”). Maju, Chesapeake and Senja beneficially own approximately 38.1%, 20.1% and 11.1%, respectively, of our common stock. As a result, Maju, Chesapeake and Senja, together, exercise significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. Furthermore, several individuals who serve as our directors are nominees of Maju, Chesapeake and Senja. This concentration of ownership and relationships with Maju, Chesapeake and Senja make it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. In addition, we have engaged, and expect to continue to engage, in related party transactions involving Chesapeake. See “Certain Relationships and Related Transactions, and Director Independence —Investors’ Rights Agreements” in Item 13 of this annual report. Furthermore, we have entered into investors’ rights agreements with Maju, Chesapeake, Senja and Hampton Asset Holding Ltd. (“Hampton”), which contain agreements regarding, among other things, director nomination, information and observer rights. See “Certain Relationships and Related Transactions, and Director Independence —Investors’ Rights Agreements” in Item 13 of this annual report. The interests of Maju, Chesapeake and Senja with respect to matters potentially or actually involving or affecting us, such as future acquisitions and financings, may conflict with the interests of our other stockholders. This continued concentrated ownership will make it more difficult for another company to acquire us and for our investors to receive any related takeover premium for their shares unless these stockholders approve the acquisition.

A significant reduction by our major stockholders of their ownership interests in us could adversely affect us.

We believe that the substantial ownership interests of Maju, Chesapeake and Senja in us provides them with an economic incentive to assist us to be successful. If Maju, Chesapeake or Senja sell all or a substantial portion of their ownership interest in us, they may have less incentive to assist in our success and their nominees that serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations. In addition, such actions may prohibit us from utilizing all or a portion of our net operating loss carryforwards. See “—Risks Related to our Business—Our ability to use our net operating loss carryforwards may be limited” in Item 1A of this annual report.

An active liquid trading market for our common stock may not develop and our stock price may be volatile.

An active and liquid trading market for our common stock may not develop or be maintained. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, our investors could lose a substantial part or all of their investment in our common stock. Consequently, our investors may not be able to sell shares of our common stock at prices equal to or greater than the price they paid.

The following factors, among others, could affect our stock price:

· our operating and financial performance;

· quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

· changes in revenue or earnings estimates or publication of reports by equity research analysts;

· speculation in the press or investment community;

· sales of our common stock by us or our stockholders, or the perception that such sales may occur;

· general market conditions, including fluctuations in actual and anticipated future commodity prices; and

· domestic and international economic, legal and regulatory factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

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The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended ( the “Exchange Act”) and the requirements of the Sarbanes-Oxley Act of 2002 ( the “Sarbanes-Oxley Act”) and the Dodd-Frank Act, may increase our costs. We may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we have to comply with numerous laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, related regulations of the U.S. Securities and Exchange Commission (the “SEC”) and the requirements of the national stock exchange on which our common stock is listed, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will require time and attention from our board of directors and management and will increase our costs and expenses. We will need to:

· institute a more comprehensive compliance function;

· expand, evaluate and maintain our system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board (United States);

· establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

· comply with corporate governance and other rules promulgated by the national stock exchange on which our common stock is listed;

· prepare and file annual, quarterly and other periodic public reports in compliance with the federal securities laws;

· prepare proxy statements and solicit proxies in connection with annual meetings of our stockholders;

· involve and retain to a greater degree outside counsel and accountants in the above activities; and

· establish a public company investor relations function.

In addition, being a public company subject to these rules and regulations required us to obtain increased director and officer liability insurance coverage and we incurred substantial costs to obtain such coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

Anti-takeover provisions in our charter documents and under Delaware law could make an acquisition of us more difficult, limit attempts by our stockholders to replace or remove our current management and limit the market price of our common stock.

Provisions in our amended and restated certificate of incorporation and amended and restated bylaws may have the effect of delaying or preventing a change of control or changes in our management. Our amended and restated certificate of incorporation and amended and restated bylaws:

· provide that our board of directors is classified into three classes of directors;

· provide that stockholders may, except as set forth in the investors’ rights agreements, which we entered into with Maju, Chesapeake, Senja and Hampton, remove directors only for cause and only with the approval of holders of at least 662/3% of our then-outstanding capital stock;

· provide that the authorized number of directors may be changed only by resolution of the board of directors;

· provide that all vacancies, including newly created directorships, may be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum, except, at any time Maju, Chesapeake, Senja and Hampton have the right to nominate a director under their respective investors’ rights agreement, any vacancy resulting from the death, disability, retirement, resignation, or removal, of a director nominated by these stockholders will be filled by the applicable nominating stockholder;

· provide that our stockholders may not take action by written consent, and may only take action at annual or special meetings of our stockholders;

· provide that stockholders, other than Maju, Chesapeake, Senja and Hampton, seeking to present proposals before a meeting of stockholders or to nominate candidates for election as directors at a meeting of stockholders must provide notice in writing in a timely manner, and also specify requirements as to the form and content of a stockholder’s notice;

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· restrict the forum for certain litigation against us to Delaware;

· not provide for cumulative voting rights (therefore allowing the holders of a majority of the shares of common stock entitled to vote in any election of directors to elect all of the directors standing for election);

· provide that special meetings of our stockholders may be called only by (1) the Chairman of the board of directors, (2) our CEO, (3) the board of directors pursuant to a resolution adopted by a majority of the total number of authorized directors or (4) stockholders with at least 25% of our then-outstanding capital stock;

· provide that, except as set forth in the investors’ rights agreements, stockholders will be permitted to amend our amended and restated bylaws only upon receiving at least 662/3% of the votes entitled to be cast by holders of all outstanding shares then entitled to vote generally in the election of directors, voting together as a single class; and

· provide that, except as set forth in the investors’ rights agreements, certain provisions of our amended and restated certificate of incorporation may only be amended upon receiving at least 662/3% of the votes entitled to be cast by holders of all outstanding shares then entitled to vote, voting together as a single class.

These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board of directors, which is responsible for appointing the members of our management. In addition, we will opt out of the provisions of Section 203 of the General Corporation Law of the State of Delaware (“DGCL”), which generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with any “interested” stockholder for a period of three years following the date on which the stockholder became an “interested” stockholder. However, our amended and restated certificate of incorporation provides substantially the same limitations as are set forth in Section 203 but also provides that Maju and Chesapeake and their affiliates and any of their direct or indirect transferees and any group as to which such persons are a party do not constitute “interested stockholders” for purposes of this provision.

We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected.

We will be required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming an accelerated filer, as defined in the SEC rules. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. For example, we anticipate the need to hire additional administrative and accounting personnel to conduct our financial reporting. We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations and our results of operations could be adversely affected.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weaknesses, 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, results of operations and financial condition.

We may not pay dividends on our common stock and, consequently, investors would achieve a return on investment only if the price of our stock appreciates.

We may not declare dividends on shares of our common stock. Additionally, we are currently limited in our ability to make cash distributions to stockholders or repurchase shares of our common stock pursuant to the terms of our Term Loan, Credit Facility and the indenture governing our 6.250% senior secured notes due May 1, 2022 (the “2022 Notes”). If we do not make cash distributions to stockholders or otherwise return cash to stockholders, a return on investment in us will only be achieved if the market price of our common stock appreciates, which may not occur, and our investors sell their shares at a profit. There is no guarantee that

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the price of our common stock in the market will exceed the price that our investors pay. See “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Dividends” in Item 5 of this annual report.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute our investors’ ownership in us.

We may sell additional shares of common stock in subsequent public offerings and may also issue securities convertible into our common stock. On February 6, 2018, we registered shares of common stock that we have granted as equity awards or may grant as equity awards under the FTS International, Inc. 2018 Equity and Incentive Compensation Plan (the “2018 Plan”). These shares may be sold freely in the public market, subject to volume limitations applicable to affiliates, applicable vesting periods and lock-up agreements.

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

If securities analysts do not publish research or reports about our business, publish inaccurate or unfavorable research or if they downgrade our stock or our sector, our common stock price and trading volume could decline.

The trading market for our common stock relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control these analysts. Furthermore, if one or more of the analysts who do cover us downgrade our stock or our industry, or the stock of any of our competitors, or publish inaccurate or unfavorable research about our business, the price of our stock could decline. If one or more of these analysts ceases coverage of us or fail to publish reports on us regularly, we could lose visibility in the market, which in turn could cause our stock price or trading volume to decline.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Our principal properties include our district offices and manufacturing facilities. We believe our facilities are in good condition and suitable for the purposes for which they are used. Below is information detailing our properties as of December 31, 2017.

Hydraulic Fracturing District Offices

Currently, we have five district offices out of which we conduct hydraulic fracturing services. The following table provides certain information about our district office locations. We own the land and facilities at each of these locations. The following table provides certain information about our district offices out of which we conduct hydraulic fracturing services office locations as of December 31, 2017.

			Facilities
District Office	Primary Area of Service	Formation	Size (Sq. Ft.) (approx.)	Acres (approx.)
Odessa, Texas	Southeast New Mexico and West Texas	Permian Basin	82,800	36
Elk City, Oklahoma	Oklahoma	SCOOP/STACK	42,330	40
Washington County, Pennsylvania	Pennsylvania, West Virginia and Ohio	Marcellus/Utica Shale	41,660	27
Pleasanton, Texas	South Texas	Eagle Ford Shale	62,950	113
Shreveport, Louisiana	East Texas and West Louisiana	Haynesville Shale	55,600	40

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We also lease a 22-acre, 250,000 square foot facility in Williamsport, Pennsylvania that we used as a district office until August 2015. We are actively seeking to sublease this facility. We may also reopen this facility if we determine it is needed for operations in the region in the future.

Wireline District Offices

Currently, we have four district offices out of which we conduct wireline services. Unless otherwise noted, we own the land and facilities at each of the locations included in the table below. The following table provides certain information about our district offices out of which we conduct wireline services as of December 31, 2017.

			Facilities
District Office	Primary Area of Service	Formation	Size (Sq. Ft.) (approx.)	Acres (approx.)
Odessa, Texas(1)(2)	Southeast New Mexico and West Texas	Permian Basin	7,200	3
Yukon, Oklahoma(1)	Oklahoma	SCOOP/STACK	10,950	10
Charleroi, Pennsylvania(1)	Ohio and Pennsylvania	Marcellus/Utica Shale	28,000	3
Pleasanton, Texas	South Texas	Eagle Ford Shale	14,375	14
Longview, Texas	East Texas and West Louisiana	Haynesville Shale	36,000	14

(1) Leased Facility

(2) In February 2018, the district office in Odessa, Texas was consolidated with the hydraulic fracturing district office in Odessa, Texas.

Manufacturing Facilities

We manufacture the proprietary, high-pressure pumps, including the fluid-ends and power-ends, as well as certain other equipment that we use in our hydraulic fracturing operations in a 89,522 square foot facility owned by us in Fort Worth, Texas.

We own a 94,050-square foot facility in Aledo, Texas that is used for equipment repair, maintenance and electronics installation. We also manufacture, refurbish and assemble certain components of our hydraulic fracturing units and other service equipment at this facility.

Principal Executive Offices

We maintain principal executive offices in Fort Worth, Texas. As of December 31, 2017 we leased approximately 90,000-square feet. In January 2018, we restructured our lease and reduced the amount of space to approximately 33,000-square feet.

Sales Offices

We have four sales offices, which we lease in Houston and Midland, Texas, Oklahoma City, Oklahoma, and Canonsburg, Pennsylvania.

Item 3. Legal Proceedings

We are involved in various legal proceedings from time to time in the ordinary course of our business. However, we are not currently involved in any legal proceedings that we believe are likely to have a material adverse effect on our operations or financial condition.

Item 4. Mine Safety Disclosures

Not applicable.

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We received aggregate net proceeds from the offering of $303 million, after deducting underwriting discounts and commissions and other estimated offering expenses payable by us. None of the underwriting discounts and commissions or other offering expenses were incurred or paid to directors or officers of ours or their associates or to persons owning 10% or more of our common stock or to any affiliates of ours.

Because the closing of our IPO occurred on February 6, 2018, as of December 31, 2017, we had not yet received the net proceeds from the sale of shares of common stock in our IPO and, therefore, had used none of the proceeds as of December 31, 2017. There has been no material change in our planned use of the net proceeds from the offering as described in our final prospectus filed with the SEC pursuant to Rule 424(b) under the Securities Act.

Item 6. Selected Financial Data

You should read this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this annual report on Form 10-K.

	Year Ended December 31,
(Dollars in millions, except per share amounts)	2017			2016			2015			2014			2013
Statements of Operations Data:
Revenue	$	1,466.1		$	532.2		$	1,375.3		$	2,368.4		$	1,925.5
Costs of revenue, excluding depreciation, depletion, and amortization	1,009.8			510.5			1,257.9			1,804.9			1,478.4
Selling, general and administrative	81.0			64.4			154.7			206.3			189.6
Depreciation, depletion and amortization (1)	86.6			112.6			272.4			294.4			355.7
Impairments and other charges (2)	1.8			12.3			619.9			9.8			1,147.4
(Gain) loss on disposal of assets, net (3)	(1.4		)	1.0			5.9			5.8			295.8
Gain on insurance recoveries	(2.9		)	(15.1		)	—			—			—
Operating income (loss)	291.2			(153.5		)	(935.5		)	47.2			(1,541.4		)
Interest expense, net	86.7			87.5			77.2			74.2			129.1
Loss (gain) on extinguishment of debt, net	1.4			(53.7		)	0.6			28.4			20.3
Equity in net loss of joint venture affiliate	0.8			2.8			1.4			—			—
Income (loss) before income taxes	202.3			(190.1		)	(1,014.7		)	(55.4		)	(1,690.8		)
Income tax expense (benefit) (4)	1.6			(1.6		)	(1.5		)	1.1			1.5
Net income (loss)	$	200.7		$	(188.5	)	$	(1,013.2	)	$	(56.5	)	$	(1,692.3	)
Net loss attributable to common stockholders (5)	$	(25.9	)	$	(370.1	)	$	(1,158.1	)	$	(172.4	)	$	(1,785.1	)
Basic and diluted earnings (loss) per share attributable to common stockholders (6)	$	(0.50	)	$	(7.14	)	$	(22.36	)	$	(1.09	)	$	(32.67	)
Shares used in computing basic and diluted earnings (loss) per share (in millions) (6)	51.8			51.8			51.8			51.8			51.8
Balance Sheet Data (at end of period):
Cash and cash equivalents	$	208.1		$	160.3		$	264.6		$	10.5		$	80.2
Total assets	$	831.0		$	616.8		$	907.4		$	1,902.3		$	1,871.0
Total debt	$	1,116.4		$	1,188.7		$	1,276.2		$	972.5		$	1,076.6
Convertible preferred stock (7)	$	349.8		$	349.8		$	349.8		$	349.8		$	349.8
Total stockholders’ equity (deficit)	$	(818.3	)	$	(1,019.0	)	$	(830.5	)	$	181.0		$	235.8
Other Data:
Adjusted EBITDA (8)	$	372.7		$	(50.8	)	$	(62.8	)	$	359.3		$	264.1
Total debt less cash and cash equivalents	$	908.3		$	1,028.4		$	1,011.6		$	962.0		$	996.4
Capital expenditures	$	64.0		$	10.3		$	79.1		$	112.2		$	79.4
Total fracturing stages (9)	30,920			16,185			21,919			26,182			22,977

(1) We recorded depletion of $4.2 million in 2013 related to our sand mines before selling those assets in the third quarter of 2013.

(2) In 2013, this amount includes a goodwill impairment of $1,047.5 million and an asset impairment of $94.0 million related to the sale of our sand mining, processing and logistics assets. In 2014, this amount related to non-essential equipment and real property we identified to sell. For a discussion of amounts recorded for the three years ended December 31, 2017, see Note 9 — “Impairments and Other Charges” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K.

(3) In 2013, this amount includes a loss of $289.7 million related to the sale of our sand mining, processing and logistics assets.

(4) Consists primarily of state margin taxes accounted for as income taxes. The tax effect of our net operating losses has not been reflected in our results because we have recorded a full valuation allowance with regards to the realization of our deferred tax assets since 2012.

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(5) Net loss attributable to common stockholders is calculated by subtracting an accreted value attributable to our convertible preferred stock from net income or loss. The annual accretion amount was $226.6 million in 2017, $181.6 million in 2016, $144.9 million in 2015, $115.9 million in 2014, and $92.8 million in 2013. For more information about the convertible preferred stock accretion, see note 7 below, Note 6 — “Convertible Preferred Stock” and Note 15 — “Earnings (Loss) Per Share” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K.

(6) Earnings per share and the related shares used to compute earnings per share have been adjusted to give effect to a 69.258777 : 1 reverse stock split that occurred in February 2018 in connection with the completion of our IPO. See Note 15 — “Earnings (Loss) Per Share” and Note 17 — “Subsequent Events” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information.

(7) The holders of the convertible preferred stock are also common stockholders of the Company and, prior to the completion of our IPO, collectively appointed 100% of our board of directors. Therefore, the convertible preferred stockholders could have directed the Company to redeem the convertible preferred stock at any time after all of our debt had been repaid; however, we did not consider this to be probable for any of the periods presented due to the amount of debt outstanding. Therefore, we have presented the convertible preferred stock as temporary equity but have not reflected any accretion of the convertible preferred stock in this table or in our Consolidated Financial Statements. See Note 6 — “Convertible Preferred Stock” and Note 15 — “Earnings (Loss) Per Share” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information. At December 31, 2017, the liquidation preference of the convertible preferred stock was estimated to be $1,132.7 million.

(8) Adjusted EBITDA is a non-GAAP financial measure that we define as earnings before interest; income taxes; and depreciation and amortization, as well as, the following items, if applicable: gain or loss on disposal of assets; debt extinguishment gains or losses; inventory write-downs, asset and goodwill impairments; gain on insurance recoveries; acquisition earn-out adjustments; stock-based compensation; and acquisition or disposition transaction costs. The most comparable financial measure to Adjusted EBITDA under GAAP is net income or loss. Adjusted EBITDA is used by management to evaluate the operating performance of our business for comparable periods and it is a metric used for management incentive compensation. Adjusted EBITDA should not be used by investors or others as the sole basis for formulating investment decisions, as it excludes a number of important items. We believe Adjusted EBITDA is an important indicator of operating performance because it excludes the effects of our capital structure and certain non-cash items from our operating results. Adjusted EBITDA is also commonly used by investors in the oilfield services industry to measure a company’s operating performance, although our definition of Adjusted EBITDA may differ from other industry peer companies.

The following table reconciles our net income (loss) to Adjusted EBITDA:

	Year Ended December 31,
(In millions)	2017			2016			2015			2014			2013
Net income (loss)	$	200.7		$	(188.5	)	$	(1,013.2	)	$	(56.5	)	$	(1,692.3	)
Interest expense, net	86.7			87.5			77.2			74.2			129.1
Income tax expense (benefit)	1.6			(1.6		)	(1.5		)	1.1			1.5
Depreciation, depletion and amortization	86.6			112.6			272.4			294.4			355.7
(Gain) loss on disposal of assets, net	(1.4		)	1.0			5.9			5.8			295.8
Loss (gain) on extinguishment of debt, net	1.4			(53.7		)	0.6			28.4			20.3
Inventory write-down	—			—			24.5			—			—
Impairment of assets and goodwill	—			7.0			572.9			9.8			1,145.2
Gain on insurance recoveries	(2.9		)	(15.1		)	—			—			—
Acquisition earn-out adjustments	—			—			(3.4		)	—			—
Stock-based compensation	—			—			1.8			2.1			1.6
Transaction costs (a)	—			—			—			—			7.2
Adjusted EBITDA (b)	$	372.7		$	(50.8	)	$	(62.8	)	$	359.3		$	264.1

(a) In 2013, these costs related to the sale of our proppant assets.

(b) For the year ended December 31, 2016, Adjusted EBITDA has not been adjusted to exclude the following items: employee severance costs of $0.8 million, supply commitment charges of $2.5 million and lease abandonment charges of $2.0 million. For the year ended December 31, 2015, Adjusted EBITDA has not been adjusted to exclude the following items: employee severance costs of $13.1 million, supply commitment charges of $11.0 million, significant legal costs of $8.1 million, lease abandonment charges of $1.8 million, and profit of $2.4 million from the sale of equipment to our joint venture affiliate.

(9) See “Business — Our Services — Hydraulic Fracturing” in Item 1 of this annual report regarding fracturing stages and the types of service agreements we use to provide hydraulic fracturing services.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes that appear elsewhere in this annual report on Form 10-K. In addition to historical consolidated financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, or beliefs. Actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this annual report on Form 10-K, particularly in “Risk Factors.”

Overview

We are one of the largest providers of hydraulic fracturing services in North America. Our services enhance hydrocarbon flow from oil and natural gas wells drilled by E&P, companies in shale and other unconventional resource formations. Our customers include Chesapeake Energy Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources, Inc., Diamondback Energy, Inc., EQT Company, Range Resources Corporation, and other leading E&P companies that specialize in unconventional oil and natural gas resources in North America. We are one of the top three hydraulic fracturing providers across our operating footprint, which consists of five of the most active major unconventional basins in the United States: the Permian Basin, the SCOOP/STACK Formation, the Marcellus/Utica Shale, the Eagle Ford Shale and the Haynesville Shale. Substantially all of our business activities support our well completion services. We manage our business, allocate resources, and assess our financial performance on a consolidated basis; therefore we do not have separate operating segments.

Significant developments in 2017 and 2018

· During the first quarter of 2017, we reached a milestone of over 10 million man-hours without a lost time incident, which is significantly better than our industry peer group, according to the U.S. Bureau of Labor Statistics.

· Due to improving industry conditions and our operational efficiencies, during 2017, we generated positive operating income for the first time since 2014 and positive net income for the first time since 2011.

· During 2017, we activated ten fleets in response to increased customer demand, which brought our total active fleet count to 27 at December 31, 2017.

· During the fourth quarter of 2017, we purchased certain components that can be used to build two additional fleets, which we expect to complete in 2018. Once completed, our total available fleet size will increase from 32 fleets to 34 fleets, representing a total of 1.7 million hydraulic horsepower. We expect the total cost of these two additional fleets to be approximately $50 million.

· In February 2018, we completed an IPO of 22.4 million shares of common stock of which 18.1 million shares were sold by the Company. The Company received net proceeds from the offering of approximately $303 million, and we intend to use the net proceeds from the offering for general corporate purposes, including debt repayments.

· In January and February 2018, we repaid $345.0 million of aggregate principal amount of long-term debt using cash on hand and proceeds received from the IPO. Our remaining principal amount of long-term debt after these repayments was $785.0 million as of February 22, 2018.

· In February 2018, we entered into a $250 million asset-based revolving credit facility.

Trends that affected our business from 2015 to 2017

Our business is cyclical, and we depend on the willingness of our customers to make expenditures to explore for, develop, and produce oil and natural gas in the United States. The willingness of our customers to undertake these activities is predominantly influenced by current and expected future prices for oil and natural gas.

Oil and natural gas prices declined significantly in 2015. As a result of these low commodity prices, our customers significantly reduced their hydraulic fracturing activities in 2015. This reduction in activity levels created an oversupply of service providers in our industry and, consequently, market prices for our services declined significantly.

In early 2016, we continued to experience very low commodity prices; however, oil and natural gas prices started improving in the second quarter of 2016 and generally increased through the remainder of 2016. The low commodity prices at the beginning of 2016 caused our customers to reduce their activity levels and request lower pricing for our services. As commodity prices improved, we experienced an increase in demand for our services in the second half of 2016. This increase in activity combined with a lower

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level of available hydraulic fracturing equipment in the market allowed us to request increased pricing for our services. Many of our customers agreed to price increases that took effect in the first quarter of 2017.

In 2017, higher commodity prices enabled our customers to significantly increase their activity levels, which resulted in an increase in the horizontal rig count from 532 at the end of 2016 to 796 at the end of 2017, according to a report by Baker Hughes, Inc. This increase in customer activity levels increased the demand for hydraulic fracturing services above the available supply. As a result, our customers agreed to price increases in 2017, and we activated additional idle fleets to meet this demand.

Business outlook

We anticipate that customer activity levels will remain strong into 2018, which should provide us an opportunity to activate additional fleets at favorable operating margins. We are also focused on minimizing cost inflation in this environment to optimize our operating margins.

Results of Operations

Revenue

We recognize revenue upon the completion of a stage of a job. A stage is considered complete when we have met the specifications set forth by our customer. We typically complete multiple stages per day during the course of a job. Invoices typically include an equipment charge and material charges for proppant, chemicals and other products consumed during the course of providing our services. See “Business — Our Services — Hydraulic Fracturing” in Item 1 of this annual report for details regarding fracturing stages and fleets and the types of agreements we use to provide hydraulic fracturing services. The following table includes certain operating statistics that affect our revenue:

	Year Ended December 31,
(Dollars in millions)	2017		2016		2015
Revenue	$	1,352.7	$	529.5	$	1,331.8
Revenue from related parties	113.4		2.7		43.5
Total revenue	$	1,466.1	$	532.2	$	1,375.3

Total fracturing stages	30,920		16,185		21,919
Active fleets (1)	23.3		15.6		23.0
Total fleets (2)	32.0		32.0		33.0

(1) Active fleets is the average number of fleets operating during the period. We had 27, 17 and 14 active fleets at December 31, 2017, 2016 and 2015, respectively.

(2) Total fleets is the total number of fleets owned during the period.

Total revenue in 2017 increased by $933.9 million from 2016. This increase was primarily due to an increase in the number of stages completed and an increase in the prices for our services in 2017, both of which were driven by increased customer demand.

The average number of active fleets during 2017 increased by 7.7 from 2016, due to increased customer demand. At December 31, 2017, we evaluated all of our idle fleets and concluded that each of these fleets is available to return to service after our maintenance personnel make any necessary repairs and confirm that the equipment is in operating condition. We believe all of our remaining inactive fleets can be returned to active service within six months, if market conditions require. We estimated the total cost to reactivate all of our inactive fleets, as of December 31, 2017, would be approximately $34 million, including capital expenditures, repairs charged as operating expense, labor costs, and other operating expenses.

The increase in revenue from related parties in 2017 were due to increases in the activity levels for Chesapeake.

Total revenue in 2016 decreased by $843.1 million from 2015. This decrease was due to a lower pricing environment for both our services and fracturing materials in 2016, lower customer activity and well completion levels in 2016, resulting in fewer stages completed, and certain customers choosing to procure their own proppants in 2016.

We began extending price concessions to our customers in the first quarter of 2015 as a result of the decline in oil and gas commodity prices that began in 2014. Our customers significantly reduced their hydraulic fracturing activities in response to the lower commodity price environment. This reduction in activity levels created an oversupply of service providers in our industry and,

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consequently, market prices for our services declined significantly. In response to the lower pricing environment and lower customer activity levels, we reduced the number of fleets operating during 2016 by an average of 7.4 fleets. However, in 2016 we improved our ability to operate our active fleets with less downtime which increased the number of stages we completed per average active fleet.

The decrease in revenue from related parties in 2016 was due to a decrease in the activity levels for Chesapeake.

Costs of revenue

The primary costs involved in conducting our hydraulic fracturing services are costs for materials used in the fracturing process and costs to operate, maintain, and repair our fracturing equipment. Costs related to the materials used in the fracturing process typically include costs for sand and other proppants, costs for chemicals added to the fracturing fluid, and freight costs to transport these materials to the well location. Costs to operate our fracturing equipment primarily consist of labor and fuel costs. While we exclude certain amounts of depreciation and amortization from our costs of revenue line item, we have included the amounts of depreciation that specifically relate to our revenue generating assets in our discussion below to provide further information regarding the total costs of generating our revenues. Costs of revenue as a percentage of total revenue is as follows:

	Year Ended December 31,
	2017				2016				2015
(Dollars in millions)	Dollars		As a Percent of Revenue		Dollars		As a Percent of Revenue		Dollars		As a Percent of Revenue
Costs of revenue, excluding depreciation	$	1,009.8	68.9	%	$	510.5	95.9	%	$	1,257.9	91.5	%
Depreciation — costs of revenue	75.6		5.1	%	98.9		18.6	%	152.3		11.0	%
Total costs of revenue	$	1,085.4	74.0	%	$	609.4	114.5	%	$	1,410.2	102.5	%

Total costs of revenue in 2017 increased by $476.0 million from 2016. This increase was primarily due to an increase in our costs of revenue, excluding depreciation, which were partially offset by a decrease in the depreciation expense for our service equipment.

Costs of revenue, excluding depreciation, in 2017 increased by $499.3 million from 2016, due to our higher number of active fleets, increased number of stages completed during 2017, and increased costs for materials used in the fracturing process.

Depreciation for our service equipment in 2017 decreased by $23.3 million from 2016. This decrease was the result of asset disposals and certain assets becoming fully depreciated. Additionally, we generally refurbish our equipment as it approaches the end of its useful life, rather than replace it by purchasing new equipment. The cost of refurbishing our equipment is significantly lower than the cost of purchasing new equipment. As more of our fleets have become comprised of refurbished assets in recent years, our depreciation has correspondingly declined.

Total costs of revenue as a percentage of total revenue decreased by 40.5 percentage points from 114.5% in 2016 to 74.0% in 2017. This change was primarily due to increased pricing for our services and increased stages completed per active fleet in 2017. These factors were partially offset by increased costs for materials used in the fracturing process.

Total costs of revenue in 2016 decreased by $800.8 million from 2015. This decrease was primarily due to a decrease in our costs of revenue, excluding depreciation, and a decrease in the depreciation expense for our service equipment.

Costs of revenue, excluding depreciation, in 2016 decreased by $747.4 million from 2015. This decrease was due to our lower number of active fleets during 2016 in response to lower customer activity and well completion levels; lower prices for materials used in the fracturing process in 2016; the effect of our cost reduction initiatives in 2016, which resulted in significant savings in labor and repair costs; and changes in customer job requirements in 2016.

Depreciation for our service equipment in 2016 decreased by $53.4 million from 2015. This decrease was the result of asset impairments, asset disposals and certain assets becoming fully depreciated. Additionally, in recent years we have chosen to refurbish our equipment as it approaches the end of its useful life, rather than to replace it by purchasing new equipment. The cost of refurbishing our equipment is significantly lower than it would be to purchase new equipment. As more of our fleet has become comprised of refurbished assets in recent years, our depreciation has correspondingly declined.

Total costs of revenue as a percentage of total revenue increased by 12.0 percentage points from 102.5% in 2015 to 114.5% in 2016. This change was primarily due to increased price concessions we extended to our customers in 2016, which have been partially offset by a lower number of active fleets in 2016, lower material costs; and our cost reduction initiatives. Our total costs of

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revenue exceeded our total revenue during these periods primarily due to the price concessions we have extended to our customers during these periods.

Selling, general and administrative expense

Selling, general and administrative expense in 2017 increased by $16.6 million from 2016. This increase was primarily due to increased incentive compensation related to our improved operating results in 2017 and increased employee-related costs due to our increased overall headcount in 2017.

Selling, general and administrative expense in 2016 decreased by $90.3 million from 2015. Approximately $60 million of this decrease was related to a decrease in employee headcount in connection with the downturn in our business. Approximately $10 million of this decrease was due to lower legal costs. The remaining decrease was primarily the result of our various cost saving initiatives.

Depreciation and amortization

The following table summarizes our depreciation and amortization:

	Year Ended December 31,
(In millions)	2017		2016		2015
Depreciation — costs of revenue (1)	$	75.6	$	98.9	$	152.3
Depreciation — other (2)	11.0		13.7		17.6
Amortization (3)	—		—		102.5
Total depreciation and amortization	$	86.6	$	112.6	$	272.4

(1) Related to service equipment included in “Property, plant, and equipment, net” on our consolidated balance sheets discussed under the “Costs of revenue” heading of this discussion and analysis.

(2) Related to all long-lived assets other than service equipment included in “Property, plant, and equipment, net” on our consolidated balance sheet.

(3) Related to definite-lived intangible assets that were written down to zero during the year ended December 31, 2015.

Depreciation and amortization in 2017 decreased by $26.0 from 2016. This decrease was primarily due to a decrease in depreciation for our service equipment, which has been previously discussed. The remaining decrease was primarily due to asset disposals and certain assets becoming fully depreciated.

Depreciation and amortization in 2016 decreased by $159.8 million from 2015. This decrease was primarily due to the cessation of amortization associated with the intangible assets that were impaired during the year ended December 31, 2015, and the decrease in depreciation for our service equipment which has been previously discussed. The remaining decrease was primarily due to asset disposals and certain assets becoming fully depreciated.

Impairments and other charges

The following table summarizes our impairments and other charges:

	Year Ended December 31,
(In millions)	2017		2016		2015
Impairment of assets and goodwill	$	—	$	7.0	$	572.9
Supply commitment charges	1.2		2.5		11.0
Lease abandonment charges	0.6		2.0		1.8
Employee severance costs	—		0.8		13.1
Inventory write-down	—		—		24.5
Acquisition earn-out adjustments	—		—		(3.4		)
Total impairments and other charges	$	1.8	$	12.3	$	619.9

Impairment of Assets and Goodwill: During 2016, we recorded asset impairments of $7.0 million related to service equipment and real property that we no longer use and identified to sell. During the first nine months of 2015, we recorded a non-cash

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In January 2016, a fire at one of our job sites in Oklahoma destroyed substantially all of the equipment in one of our fleets. These assets were insured at values greater than their carrying values. We received $19.0 million of insurance recovery proceeds for these assets, which exceeded their carrying values by $15.1 million.

Interest expense, net

Interest expense, net of interest income, in 2017 decreased by $0.8 million from 2016. This decrease was primarily due to a lower average long-term debt balance, which was partially offset by higher average interest rates in 2017 for our senior floating rate notes due June 2020.

Interest expense, net of interest income, in 2016 increased by $10.3 million from 2015. The increase was due to a higher average long-term debt balance and a higher average interest rate in 2016 for our senior floating rate notes due June 2020.

Gain on extinguishment of debt, net

In 2017, we repaid $60.0 million of aggregate principal amount of our senior floating rate notes due June 2020. We recognized a loss on debt extinguishment of $1.8 million. In 2017, we also repurchased $17.3 million of aggregate principal amount of senior notes due May 2022 in the qualified institutional market. We recognized a gain on debt extinguishment of $0.4 million.

In the third quarter of 2016, we completed a tender offer and subsequent purchases in the qualified institutional market for a portion of our long-term debt in which we repurchased $90.7 million of aggregate principal amount of long-term debt and recorded a gain on debt extinguishment of $52.3 million.

Income tax expense

Income tax expense was $1.6 million in 2017. This amount consisted of state margin taxes accounted for as income taxes. In 2012, we recorded a valuation allowance to reduce our net deferred tax assets to zero. We continue to provide a valuation allowance against all deferred tax assets in excess of our deferred tax liabilities. As a result, we did not record any U.S. federal or state income tax expense or benefit related to our income or losses in 2017, 2016 or 2015. See Note 12 — “Income Taxes” in Notes to our Audited Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information regarding our income taxes and valuation allowance.

Liquidity and Capital Resources

Sources of Liquidity

At December 31, 2017, we had $208.1 million of cash, which represented our total liquidity position. We believe that our cash and cash provided by operations will be sufficient to fund our operations and capital expenditures.

In February 2018, we entered into a $250 million asset-based revolving credit facility. The maximum availability of credit under the credit facility is limited at any time to the lesser of $250 million or the borrowing base. The borrowing base is based on percentages of eligible accounts receivable and eligible inventory and is subject to certain reserves. In an event of default or if the amount available under the credit facility is less than either 10% of our maximum availability or $12.5 million, we will be required to maintain a minimum fixed charge coverage ratio of 1.0 to 1.0. If at any time borrowings and letters of credit issued under the credit facility exceed the borrowing base, we will be required to repay an amount equal to such excess. See Note 17 — “Subsequent Events” in Notes to our Audited Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information on our new credit facility.

Cash Flows

The following table summarizes our cash flows:

	Year Ended December 31,
(In millions)	2017			2016			2015
Net income (loss) adjusted for non-cash items	$	288.8		$	(130.9	)	$	(133.3	)
Changes in operating assets and liabilities	(108.8		)	21.1			183.9
Net cash provided by (used in) operating activities	180.0			(109.8		)	50.6
Net cash (used in) provided by investing activities	(54.6		)	43.1			(97.9		)
Net cash provided by (used in) financing activities	(77.6		)	(37.6		)	301.4
Net increase (decrease) in cash	47.8			(104.3		)	254.1
Cash, beginning of period	160.3			264.6			10.5
Cash, end of period	$	208.1		$	160.3		$	264.6

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Cash flows from operating activities have historically been a significant source of liquidity we use to fund capital expenditures and repay our debt. Changes in cash flows from operating activities are primarily affected by the same factors that affect our net income, excluding non-cash items such as depreciation and amortization, stock-based compensation, and impairments of assets.

Cash flows from operating activities: Net cash provided by operating activities was $180.0 million in 2017 compared to net cash used in operating activities of $109.8 million in 2016. Cash flows from operating activities consists of net income or loss adjusted for non-cash items and changes in operating assets and liabilities. Net income or loss adjusted for non-cash items resulted in a cash increase of $288.8 million and a cash decrease of $130.9 million in 2017 and 2016, respectively. This change was primarily due to higher earnings in 2017. The net change in operating assets and liabilities resulted in a cash decrease of $108.8 million and a cash increase of $21.1 million 2017 and 2016, respectively. The net change in operating assets and liabilities for 2017 was primarily due to an increase in working capital resulting from our increased activity level.

Net cash used in operating activities was $109.8 million in 2016 compared to net cash provided by operating activities of $50.6 million in 2015. Net loss adjusted for non-cash items resulted in a cash decrease of $130.9 million and $133.3 million in 2016 and 2015, respectively. The net change in operating assets and liabilities resulted in a cash increase of $21.1 million and $183.9 million in 2016 and 2015, respectively. The net change in operating assets and liabilities in 2016 was primarily due to decreased accounts receivable and inventories, partially offset by decreased accrued expenses, which were all due to our lower activity levels in 2016.

Cash flows from investing activities: Net cash used in investing activities was $54.6 million in 2017 compared to cash provided by investing activities of $43.1 million in 2016. This change was primarily due to increased capital expenditures in 2017, decreased asset disposal proceeds in 2017 and decreased insurance recovery proceeds received in 2017. The increase in capital expenditures in 2017 was due to our increased operations and fleet reactivations in 2017 as well as an approximate $10 million purchase of certain asset components that we plan to use to build two additional fleets in 2018.

Net cash provided by investing activities in 2016 was $43.1 million compared to net cash used in investing activities of $97.9 million in 2015. This change was primarily due to reduced capital expenditures in 2016, increased asset disposal proceeds in 2016, and insurance recovery proceeds received in 2016.

Cash flows from financing activities: Net cash used in financing activities was $77.6 million and $37.6 million in 2017 and 2016, respectively, which was comprised of debt repayments.

Net cash provided by financing activities was $301.4 million in 2015. This net cash flow was due to the issuance of $350 million aggregate principal amount of our senior floating rate notes due June 2020, which was partially offset by a repayment of borrowings under our previously existing revolving credit facility.

Cash Requirements

Contractual Commitments and Obligations

The following table summarizes our contractual commitments and obligations at December 31, 2017:

			Payments Due by Period
			Less Than						More than
(In millions)	Total		1 Year		1-3 Years		3-5 Years		5 Years

Long-term debt obligations	$	1,130.0	$	—	$	290.0	$	840.0	$	—
Interest obligations (1) (2)	270.0		79.2		144.7		46.1		—
Operating lease obligations	44.1		14.3		21.4		7.0		1.4
Purchase obligations	405.0		79.8		133.4		95.8		96.0
Total	$	1,849.1	$	173.3	$	589.5	$	988.9	$	97.4

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(1) Our Term Loan bears interest at a variable rate based on LIBOR plus a margin of 4.75% per annum, but never less than 5.75% per annum due to a 1.00% LIBOR floor. The future interest payment amounts included in the table for these notes have been calculated at the rate in effect at December 31, 2017.

(2) Our senior floating rate notes due June 2020 bear interest at a variable rate based on LIBOR plus a margin of 7.5% per annum. The future interest payment amounts included in the table for these notes have been calculated at the rate in effect at December 31, 2017.

In 2017, we repaid $77.3 million of aggregate principal amount of long-term debt. We recognized a corresponding loss on debt extinguishment of $1.4 million. See Note 5 — “Debt” in Notes to our Audited Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information on our long-term debt obligations.

In February 2018 the Company completed an IPO of its common stock and used proceeds from the offering and cash on hand to repay certain long-term debt. See Note 17 — “Subsequent Events” in Notes to our Audited Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information. The following table summarizes our contractual commitments and obligations after giving effect to these debt repayments in 2018:

			Payments Due by Period
			Less Than						More than
(In millions)	Total		1 Year		1-3 Years		3-5 Years		5 Years

Long-term debt obligations	$	785.0	$	—	$	—	$	785.0	$	—
Interest obligations (1)	194.5		50.2		99.4		44.9		—
Operating lease obligations	44.1		14.3		21.4		7.0		1.4
Purchase obligations	405.0		79.8		133.4		95.8		96.0
Total	$	1,428.6	$	144.3	$	254.2	$	932.7	$	97.4

Capital Expenditures

The nature of our capital expenditures consists of a base level of investment required to support our current operations and amounts related to growth and company initiatives. Our capital expenditures for 2017 represented the amount necessary to support our current operations and fleet reactivations. We estimate capital expenditures in 2018 will range from $130 million to $150 million. During the fourth quarter of 2017, we purchased certain components that can be used to build two additional fleets, which we expect to complete in 2018. Once completed, our total available fleet size will increase from 32 fleets to 34 fleets, representing a total of 1.7 million hydraulic horsepower. We expect our capital expenditures related to these two additional fleets to be approximately $50 million, of which approximately $10 million was spent in 2017 and the remainder will be spent in 2018. Our remaining estimate for capital expenditures will be used to support our current operations and fleet reactivations in 2018. Our cash and any cash provided by operations will be used to fund our capital expenditure needs, which we believe will be sufficient to support our operations in 2018. We continuously evaluate our capital expenditures and the amount we ultimately spend will primarily depend on industry conditions.

Off-Balance Sheet Arrangements

Except for our normal operating leases, we do not have any off-balance sheet financing arrangements, transactions, or special purpose entities.

Critical Accounting Estimates

The preparation of our consolidated financial statements and related notes requires us to make estimates that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures of contingent assets and liabilities. We base these estimates on historical results and various other assumptions believed to be reasonable, all of which form the basis for making estimates concerning the carrying values of assets and liabilities that are not readily available from other sources. Actual results may differ from these estimates.

In the notes accompanying the consolidated financial statements included elsewhere in this annual report on Form 10-K, we describe the significant accounting policies used in the preparation of our consolidated financial statements. We believe that the following represent the most significant estimates and management judgments used in preparing the consolidated financial statements.

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Property, Plant, and Equipment

We calculate depreciation based on the estimated useful lives of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, the cyclical nature of our business, which results in fluctuations in the use of our equipment and the environments in which we operate, could cause us to change our estimates, thus affecting the future calculation of depreciation.

We continuously perform repair and maintenance expenditures on our service equipment. Expenditures for renewals and betterments that extend the lives of our service equipment, which may include the replacement of significant components of service equipment, are capitalized and depreciated. Other repairs and maintenance costs are expensed as incurred. The determination of whether an expenditure should be capitalized or expensed requires management judgment with regard to the effect of the expenditure on the useful life of the equipment.

We separately identify and account for certain significant components of our hydraulic fracturing units including the engine, transmission, and pump, which requires us to separately estimate the useful lives of these components.

Definite-lived Intangible Assets

The amortization of our definite-lived intangible assets reflected in our consolidated statements of operations was $102.5 million for the year ended December 31, 2015. These intangible assets were primarily related to customer relationships and proprietary chemical blends acquired in business acquisitions. We calculated amortization for these assets based on their estimated useful lives. When these assets were recorded, we made estimates with respect to their useful lives that we believed were reasonable. However, these estimates contained judgments regarding the future utility of these assets and a change in our assessment of the useful lives of these assets could have materially changed the future calculation of amortization. At December 31, 2015, we impaired all of our definite-lived intangible assets.

Impairment of Long-Lived Assets, Goodwill and Other Intangible Assets

Long-lived assets, such as property, plant, equipment and definite-lived intangible assets, are reviewed for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable, such as insufficient cash flows or plans to dispose of or sell long-lived assets before the end of their previously estimated useful lives. If the carrying amount is not recoverable, we recognize an impairment loss equal to the amount by which the carrying amount exceeds fair value. We estimate fair value based on the income, market or cost valuation techniques. Our fair value calculations for long-lived assets and intangible assets contain uncertainties because they require us to apply judgment and estimates concerning future cash flows, strategic plans, useful lives and assumptions about market performance. We also apply judgment in the selection of a discount rate that reflects the risk inherent in our current business model.

We have historically acquired goodwill and indefinite-lived intangible assets related to business acquisitions. Goodwill represents the excess of the purchase price over the fair value of net assets acquired. We review our goodwill and indefinite-lived intangible assets on an annual basis, at the beginning of the fourth quarter, and whenever events or changes in circumstances indicate the carrying value of goodwill or an intangible asset may exceed its fair value. If the carrying value of goodwill or an intangible asset exceeds its fair value, we recognize an impairment loss for this difference. Our impairment loss calculations for goodwill and indefinite-lived intangible assets contain uncertainties because they require us to estimate fair values of our reporting units and intangible assets, respectively. We estimate fair values based on various valuation techniques such as discounted cash flows and comparable market analyses. These types of analyses contain uncertainties because they require us to make judgments and assumptions regarding future profitability, industry factors, planned strategic initiatives, discount rates and other factors.

Unconditional Purchase Obligations

We have historically entered into supply arrangements, primarily for sand, with our vendors that contain unconditional purchase obligations. These represent obligations to transfer funds in the future for fixed or minimum quantities of goods or services at fixed or minimum prices, such as “take-or-pay” contracts. We enter into these unconditional purchase obligation arrangements in the normal course of business to ensure that adequate levels of sourced product are available to us. To account for these arrangements, we must monitor whether we may be required to make a minimum payment to a vendor in a future period because our projected inventory purchases may not satisfy our minimum commitments. If we conclude that it is probable that we will make a minimum payment under these arrangements, we will record an estimated loss for these commitments in the current period.

A loss related to an unconditional purchase obligation contains uncertainties because it requires us to make assumptions and apply judgment to forecast future demand, determine the ultimate allocation of a commitment shortfall to our various vendors, and

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Directors and Executive Officers.

The executive officers and directors are listed below with a description of their experience and certain other information.

Name	Age*	Position
*Executive Officers*
Michael J. Doss	45	Chief Executive Officer, Director
Buddy Petersen	52	Chief Operating Officer
Lance Turner	38	Chief Financial Officer and Treasurer
Karen D. Thornton	48	Chief Administrative Officer
Jennifer L. Keefe	45	Senior Vice President, General Counsel and Chief Compliance Officer
Perry A. Harris	60	Senior Vice President, Commercial

*Non-Employee Directors*
Goh Yong Siang (2)	66	Chairman
Domenic J. Dell’Osso, Jr. (2) (3)	41	Director
Bryan J. Lemmerman (1)	43	Director
Ong Tiong Sin (1) (2) (3)	53	Director
Boon Sim (3)	55	Director
Carol J. Johnson (1)	58	Director

* Age as of March 7, 2018.

(1) Member of the audit committee.

(2) Member of the compensation committee.

(3) Member of the nominating and corporate governance committee.

Michael J. Doss was elected as a director of the Company immediately following effectiveness of the Company’s registration statement on February 1, 2018. He has served as the Company’s Chief Executive Officer since October 2015. He joined the Company in January 2014 as Senior Vice President—Finance and Treasurer and was named Chief Financial Officer in December 2014. From July 2008 until joining the Company, Mr. Doss served as Vice President of Finance of Energy Transfer Partners, L.P. (“ETP”), a master limited partnership that owns and operates a portfolio of energy assets in the United States and then as Vice President of Strategic Planning for its affiliate Energy Transfer Equity, L.P. Prior to ETP, he was a Senior Credit Officer at Moody’s Investors Service, a provider of credit ratings, research and risk analysis, covering a diverse portfolio of oil and natural gas issuers. Prior to that, Mr. Doss spent more than seven years of his career in public accounting at Ernst & Young LLP serving clients in the oil and natural gas industry. He earned a Bachelor of Business Administration and Master of Professional Accounting from the University of Texas at Austin. Mr. Doss also earned a Master of Business Administration from Columbia Business School.

Buddy Petersen has served as the Company Chief Operating Officer (“COO”), since October 2015. He joined the Company in June 2015 as Senior Vice President, Continuous Improvement and was named Senior Vice President of Operations and Wireline in August 2015. He has over 25 years of experience in the oil and natural gas industry. Prior to joining the Company, Mr. Petersen was COO of GoFrac LLC, an oil and natural gas stimulation company from October 2014 to June 2015, Vice President of Sales for Frac-Chem Inc., an oilfield chemical manufacturer and supplier and an affiliate of Koch Industries, from August 2013 to October 2014, President and COO of Compass Well Services LLC, a hydraulic fracturing and cementing services company from October 2010 to August 2013, and COO of Allied Cementing Co., a company providing cementing and acidizing services to the oil and natural gas industry from October 2007 to October 2010. Mr. Petersen spent 14 years working in various roles of increasing responsibility with Halliburton Energy Services (“Halliburton”), an oilfield services and products company. In April 2017, Mr. Petersen joined the board of directors of L.O. Transport, Inc., a company that provides transportation services to oil and gas producers. He earned a bachelor’s degree in civil engineering from New Mexico State University.

Lance Turner has served as the Company’s Chief Financial Officer and Treasurer since October 2015. He joined the Company in April 2014 as Director of Finance and was promoted to Vice President of Finance in January 2015. Prior to joining the Company, Mr. Turner spent approximately 11 years with Ernst & Young LLP, with the majority of that time in its transaction services group coordinating and advising clients on buy side and sell side transactions in various industries. He earned a Bachelor of Business

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Administration and Master of Professional Accounting from the University of Texas at Austin and is a Certified Public Accountant in the state of Texas.

Karen D. Thornton has served as the Company’s Chief Administrative Officer since March 2017. Ms. Thornton previously served as the Company’s Vice President of Human Resources from the time she joined the Company in March 2014. Prior to joining the Company, she was an independent consultant at Alkat Consulting and served as the Strategic Human Capital Management Lead focusing on human resources and payroll application implementations for Darling Ingredients Inc., an Irving, Texas company providing a global growth platform for the development and production of sustainable natural ingredients, from June 2013 to March 2014. Prior to Alkat Consulting, Ms. Thornton served in various leadership positions, including the Vice President, Human Resources & Management Services for the Emergency Medical Services Corporation in Dallas, Texas, from 2001 to 2012. Ms. Thornton received her Bachelor of Science Industrial Management from Purdue University and her Master of Business Administration from The University of Texas at Austin’s Red McCombs School of Business.

Jennifer L. Keefe has served as the Company’s Senior Vice President, General Counsel and Chief Compliance Officer since March 2017. Ms. Keefe previously served as our Deputy General Counsel managing our Commercial Litigation, Employment Compliance and Risk Departments from the time she joined our Company in September 2014. Prior to joining our Company, she was a partner in the Dallas, Texas office of the international law firm of Squire Patton Boggs, where she joined in February 1997. Ms. Keefe received her Bachelor of Arts in Political Science and Spanish from Vanderbilt University and her Juris Doctor from Southern Methodist University Dedman School of Law. She is licensed to practice law in the state of Texas.

Perry A. Harris has served as the Company’s Senior Vice President, Commercial since July 2015. Mr. Harris joined the Company as Senior Vice President of Wireline Operations in December 2014 upon our acquisition of J-W Wireline Company, a case-hole wireline company. Prior to the acquisition, Mr. Harris was President of J-W Wireline Company from February 2012 to December 2014. He has more than 36 years of experience in the oil and natural gas industry, including over 24 years at Halliburton. At Halliburton, Mr. Harris held various leadership positions, including Northeast U.S. Area Operations Manager, Northeast U.S. Senior District Manager and Wireline Global Business Development, Marketing & Technology Manager. He earned a bachelor degree in mining engineering from West Virginia University.

Goh Yong Siang has served as a director of the Company since May 2011 and currently is Chairman of the board of directors. Mr. Goh is a board designee of Maju, an indirect wholly owned subsidiary of Temasek, an investment company based in Singapore and our largest stockholder. From July 2011 until his retirement in 2013, Mr. Goh served as the Head of Australia & New Zealand for Temasek. He served as Co-Head, Organization & Leadership for Temasek from April 2010 to July 2011 and Head of Strategic Relations for Temasek from August 2006 to April 2010. Prior to joining Temasek, Mr. Goh served as President of ST Engineering (USA). Mr. Goh provides significant insight to our board of directors, particularly as it relates to financial matters and business knowledge, from his many years of experience at Temasek and other private equity firms. Mr. Goh’s international expertise is also beneficial to our board of directors.

Domenic J. Dell’Osso, Jr. has served as a director of the Company since May 2011. He is a board designee of Chesapeake, an oil and natural gas producing company, and one of our largest stockholders. Currently, Mr. Dell’Osso is Executive Vice President and Chief Financial Officer of Chesapeake Parent, one of our customers, a position he has held since November 2010. Mr. Dell’Osso served as Vice President—Finance of Chesapeake Parent and Chief Financial Officer of Chesapeake Parent’s wholly owned subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010. Prior to joining Chesapeake Parent, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from April 2006 to August 2008 and Banc of America Securities from 2004 to April 2006. Mr. Dell’Osso previously served as a director of the general partner of Chesapeake Midstream Partners from 2011 to 2014 and as a director of Chaparral Energy, Inc. from 2013 to 2014. Mr. Dell’Osso brings extensive financial and business expertise, as well as in-depth energy industry knowledge, to our board of directors from his service as Chief Financial Officer of Chesapeake Parent and from his background in investment banking.

Bryan J. Lemmerman has served as a director of the Company since February 2013. He is a board designee of Chesapeake. He is currently Vice President—Business Development at Chesapeake Parent, a position he has held since June 2015. He served as Vice President—Marketing at Chesapeake Parent from October 2014 to June 2015, Vice President—Strategic Planning at Chesapeake Parent from October 2013 to October 2014, Vice President—Finance at Chesapeake Parent from January 2012 to September 2013 and Director—Finance at Chesapeake Parent from May 2010 to December 2011. Mr. Lemmerman has served as a director of Sundrop Fuels, Inc. since 2012. Prior to joining Chesapeake Parent, Mr. Lemmerman served as a consultant to various oil and natural gas companies and private equity firms. Mr. Lemmerman was also a portfolio manager at hedge funds Highview Capital Management and Ritchie Capital Management. Mr. Lemmerman provides extensive energy industry and business development insight to our board of directors from his service at Chesapeake Parent and from his background as a consultant to hedge funds, family offices and private equity firms.

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Ong Tiong Sin has served as a director of the Company since May 2011. Mr. Ong is a board designee of Senja, an investment company affiliated with RRJ and one of our largest stockholders. Mr. Ong is the founder, Chairman and Chief Executive Officer of RRJ, the general partner of RRJ Capital Master Fund I, L.P., a private equity fund established in March 2011 which focuses on private equity investments in China and Southeast Asia. From January 2008 to March 2011, Mr. Ong was Chief Executive Officer of Hopu Fund, a China-focused private equity fund. Previously, Mr. Ong had a 15-year career with Goldman, Sachs & Co., an investment banking, securities and investment management firm. Based in Beijing, he was a co-head of Goldman Sachs Asian Ex-Japan Investment Banking Division. Mr. Ong became a managing director in the corporate finance department of a subsidiary of Goldman Sachs in 1996 and a partner in 2000. Prior to his transfer to Beijing, Mr. Ong was the co-president of Goldman Sachs Singapore and had previously worked in investment banking divisions in Hong Kong and New York. Mr. Ong brings extensive financial and banking expertise to our board of directors, and his experience in private equity provides a great deal of knowledge with respect to investment in and operations of companies.

Boon Sim has served as a director of the Company since June 2013. Mr. Sim is a board designee of Maju. Since September 2017, he has served as the Managing Partner of Artius Capital Partners. He was previously Advisory Senior Director of Temasek from April 2016 to December 2017 and President, Americas Group, Head of Markets Group and Head of Credit and Life Science Portfolio at Temasek from June 2012 to April 2016. Prior to joining Temasek, Mr. Sim was the Global Head of Mergers & Acquisitions (“M&A”), at Credit Suisse, an investment banking, securities and investment management firm based in New York and a member of Credit Suisse Investment Bank’s Operating Committee. During a 20 year career at Credit Suisse and The First Boston Corporation, a predecessor company of Credit Suisse, Mr. Sim had held various management positions including Head of M&A Americas and Co-head of Technology Group. Prior to joining The First Boston Corporation, Mr. Sim was a design engineer at Texas Instruments Inc., a semiconductor design and manufacturing company, focusing on semiconductor design. Mr. Sim provides significant insight to our board of directors, particularly as it relates to financial matters and business knowledge, from his many years of experience at Temasek, Credit Suisse and The First Boston Corporation.

Carol J. Johnson was appointed as a director of the Company immediately following the effectiveness of our amended and restated certificate of incorporation and amended and restated bylaws on February 1, 2018. She served as President and Chief Operating Officer of AlliedBarton Security Services, LLC, a manned guarding physical security company, from 2014 to 2016. From 2011 to 2013, Ms. Johnson served as Senior Vice President, Client Experience at AlliedBarton Security Services. Ms. Johnson has served on the board of directors of The Federal Reserve Bank of Philadelphia since 2015. She has also been a director of the Union League Club of Philadelphia since 2016 and a director of the National Association of Corporate Directors—Philadelphia Chapter since 2017. Ms. Johnson brings strategic leadership, operational and financial expertise to our board of directors from her background in leading, managing and growing companies.

Board Composition

Prior to closing our IPO, each of Goh Yong Siang, Domenic J. Dell’Osso, Jr., Bryan J. Lemmerman, Ong Tiong Sin, Boon Sim served as directors pursuant to the board composition provisions of our amended and restated stockholders agreement, that we entered into with certain of our investors, which is further described in “Certain Relationships and Related Party Transactions—Stockholders Agreement” in Item 13 of this annual report. The amended and restated stockholders agreement was terminated prior to the completion of the IPO.

On February 1, 2018, prior to our IPO, the Company entered into an investors’ rights agreement with Maju and Chesapeake, pursuant to which, each of Maju and Chesapeake will have the right to nominate (1) two directors so long as it beneficially owns at least 15% of our then-outstanding shares of capital stock or (2) one director so long as it beneficially owns at least 5% but less than 15% of our then-outstanding shares of capital stock. In addition, the Company entered into an investors’ rights agreement with Senja and Hampton, pursuant to which, Senja and Hampton will have the right to collectively nominate one director so long as it beneficially owns at least 5% of our then-outstanding shares of capital stock.

Our certificate of incorporation and bylaws, as amended and restated, provide that the authorized number of directors may be changed only by resolution of the board of directors. Our amended and restated certificate of incorporation also provide that directors may only be removed for cause. To remove a director not appointed by Maju, Chesapeake or Senja for cause, 662/3% of the voting power of the outstanding voting stock must vote as a single class to remove the director at an annual or special meeting. Our amended and restated certificate of incorporation also provide that, if a director is removed or if a vacancy occurs due to either an increase in the size of the board or the death, resignation, disability, disqualification or other cause, the vacancy will be filled solely by the affirmative vote of a majority of the remaining directors then in office, even if less than a quorum remain, or by a sole remaining director and shall not be filled by the stockholders. However, at any time Maju, Chesapeake, Senja and Hampton have the right to nominate a director under their respective investors’ rights agreement, any vacancy resulting from the death, resignation, disability, disqualification or other cause, of a director nominated by these stockholders will be filled by the applicable nominating stockholder.

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· pre-approving audit and permissible non-audit services, and the terms of such services, to be provided by our independent registered public accounting firm;

· reviewing annually a report by our independent registered public accounting firm regarding the independent registered public accounting firm’s internal quality control procedures and various issues relating thereto;

· coordinating the oversight and reviewing the adequacy of our internal control over financial reporting with both management and our independent registered public accounting firm;

· reviewing and discussing with management and our independent registered public accounting firm our annual and quarterly financial statements and related disclosures;

· periodically reviewing legal compliance matters, periodically reviewing significant accounting and other financial risks or exposures to our company and reviewing and, if appropriate, approving all transactions between our company or its subsidiaries and any related party (as described in Item 404 of Regulation S-K);

· periodically reviewing our code of business conduct and ethics;

· establishing policies for the hiring of employees and former employees of our independent registered public accounting firm; and

· reviewing the audit committee report required by SEC regulations to be included in our annual proxy statement.

The audit committee also has the power to investigate any matter brought to its attention within the scope of its duties and the authority to retain counsel and advisors at our expense to fulfill its responsibilities and duties.

Compensation Committee

Our compensation committee consists of Goh Yong Siang, Ong Tiong Sin, and Domenic J. Dell’Osso, Jr., with Mr. Goh serving as chair of the committee. Our board of directors has determined that each of Messrs. Goh, Ong, and Dell’Osso are independent under the NYSE listing standards and Rule 10C-1 of the Exchange Act and that each of Messrs. Goh and Ong qualifies as a “non-employee director” within the meaning of Rule 16b-3(d)(3) under the Exchange Act and as “outside directors” within the meaning of Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”). Our compensation committee is responsible for developing and maintaining our compensation strategies and policies. Our compensation committee is responsible for, among other things:

· reviewing and approving our overall executive and director compensation philosophy to support our overall business strategy and objectives;

· reviewing and approving, or as appropriate, recommending to our board of directors for approval, base salary, cash incentive compensation, equity compensation, and severance rights for our executive officers, including our CEO;

· administering our broad-based equity incentive plans, including the granting of stock awards;

· preparing any report on executive compensation required by the applicable rules and regulations of the SEC and other regulatory bodies;

· managing such other matters that are specifically delegated to our compensation committee by applicable law or by the board of directors from time to time; and

· retaining and terminating compensation consultants to assist in the evaluation of our compensation and approving the fees and other retention terms of such compensation consultants.

The compensation committee also has the power to investigate any matter brought to its attention within the scope of its duties and authority to retain counsel and advisors at our expense to fulfill its responsibilities and duties.

Nominating and Corporate Governance Committee

Our nominating and corporate governance committee consists of Domenic J. Dell’Osso, Jr., Ong Tiong Sin, and Boon Sim, with Mr. Dell’Osso serving as chair of the committee. Our board of directors has determined that each of Messrs. Dell’Osso, Ong, and Sim is independent as defined by NYSE rules.

Our nominating and corporate governance committee oversees and assists our board of directors in reviewing and recommending corporate governance policies and nominees for election to our board of directors and its committees. The nominating and corporate governance committee will be responsible for, among other things:

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· assessing, developing, and communicating with our board of directors concerning the appropriate criteria for nominating and appointing directors, including the size and composition of the board of directors, corporate governance policies, applicable listing standards, laws, rules and regulations, and other factors considered appropriate by our board of directors;

· identifying and recommending to our board of directors the director nominees for meetings of our stockholders, or to fill a vacancy on the board of directors, except as set forth in the investors’ rights agreements;

· having sole authority to retain any search firm used to identify director candidates and approve the search firm’s fees and other retention terms;

· assessing and recommending to the board of directors the composition of each of its committees;

· reviewing, as necessary, any executive officer’s request to accept a directorship position with another company;

· developing, assessing and making recommendations to our board of directors concerning corporate governance matters, including appropriate revisions to our amended and restated certificate of incorporation, amended and restated bylaws, corporate governance guidelines and committee charters;

· overseeing the management continuity and succession planning process with respect to our officers;

· overseeing an annual evaluation of our board of directors, its committees, and each director;

· developing with management and monitoring the process of orienting new directors and continuing education for all directors; and

· regularly reporting its activities and any recommendations to our board of directors.

The nominating and corporate governance committee also has the power to investigate any matter brought to its attention within the scope of its duties. It also has the authority to retain counsel and advisors at our expense for any matters related to the fulfillment of its responsibilities and duties.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than ten percent of a registered class of our equity securities, to file with the SEC initial reports of ownership and reports of changes in ownership of common stock and other equity securities of our company. Executive officers, directors and greater than ten percent stockholders are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file.

Our executive officers, directors and ten percent stockholders did not become subject to the reporting requirements of Section 16(a) until February 2, 2018 and, therefore, there were no reports required during the fiscal year ended December 31, 2017.

Code of Business Conduct and Ethics

The board of directors has adopted an amended and restated code of business conduct and ethics that is applicable to all of our employees, officers, and directors, including our principal executive officer, principal financial officer, principal accounting officer, or persons performing similar functions. The code of business conduct and ethics is available on our website at www.ftsi.com. Any waiver of this code for any executive officer or director may be made only by our board of directors or a committee of the board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE. We expect that any amendment or waiver to the code will be disclosed on our website.

Item 11. Executive Compensation

Our compensation committee consists of Goh Yong Siang, Ong Tiong Sin, and Domenic J. Dell’Osso, Jr., with Mr. Goh serving as chair of the committee. Our board of directors has determined that each of Messrs. Goh, Ong, and Dell’Osso are independent under the NYSE listing standards and Rule 10C-1 of the Exchange Act and that each of Messrs. Goh and Ong qualifies as a “non-employee director” within the meaning of Rule 16b-3(d)(3) under the Exchange Act and as “outside directors” within the meaning of Section 162(m) of the Code. Our compensation committee will be responsible for, among other things:

· reviewing and approving our overall executive and director compensation philosophy to support our overall business strategy and objectives;

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· administering our broad-based equity incentive plans, including the granting of stock awards;

· preparing any report on executive compensation required by the applicable rules and regulations of the SEC and other regulatory bodies;

· managing such other matters that are specifically delegated to our compensation committee by applicable law or by the board of directors from time to time; and

· retaining and terminating compensation consultants to assist in the evaluation of our compensation and approving the fees and other retention terms of such compensation consultants.

Additional information regarding the processes and procedures of the Compensation Committee in recommending and determining compensation for our directors and executive officers is set forth below under the heading “Compensation Discussion and Analysis.”

COMPENSATION DISCUSSION AND ANALYSIS

In this section, we describe and discuss the principles and policies used in setting the compensation of our named executive officers and other executive officers. Our named executive officers for the fiscal year ended December 31, 2017 were:

· Michael J. Doss, Chief Executive Officer;

· Lance Turner, Chief Financial Officer and Treasurer;

· Buddy Petersen, Chief Operating Officer;

· Perry A. Harris, Senior Vice President, Commercial; and

· Karen Thornton, Chief Administrative Officer.

Objective and Design of Compensation Policy

The objective of the Company’s executive compensation policy is to:

· attract and retain exceptional individuals as executive officers;

· provide key executives with motivation to perform to the full extent of their abilities to maximize the performance of the Company and deliver enhanced value to the Company’s shareholders; and

· compensate key executives for outstanding performance.

What the Company’s Executive Compensation Program is Designed to Reward

Overall, the Company’s executive compensation program is designed to reward the contributions of each individual executive officer, to ensure that each executive officer’s interest is aligned with those of the Company’s shareholders, and to provide sufficient incentives to executive officers to ensure their dedication to the Company. As discussed further below, the Company seeks to achieve these goals by providing sufficient base salaries to compensate executive officers for the day-to-day performance of their duties and awarding cash bonuses when the executive attains the personal or corporate goals and objectives established by the Company. Also, from time to time, the Company grants equity-based awards when it believes that such equity awards will further align the interests of executive officers with those of the Company’s shareholders and provide an additional incentive to executive officers to contribute to the achievement of the Company’s financial and strategic objectives.

General Executive Compensation Policies

Process for Setting Total Compensation

Since the Company was privately held until February 2, 2018, the compensation committee did not retain an outside consultant or advisor to advise it regarding the Company’s executive compensation program for fiscal year 2017. The compensation committee has historically reviewed the compensation policies and levels of companies that are engaged in the same industry as the Company, and has conducted the review without the advice of an outside consultant or advisor. While the compensation committee conducted this review and considered the information prior to setting compensation levels for fiscal year 2017, it did not rely on any peer group analysis or engage in any benchmarking.

Upon hiring or promoting a named executive officer, the compensation committee will set the initial levels of base salary and other compensation on the basis of subjective factors, including experience, individual achievements, and level of responsibility assumed at the Company, and may consider market compensation practices from time to time, as discussed in the preceding paragraph. Actual base salaries, cash bonuses, and equity-based awards for each named executive officer may be adjusted from year to

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on the results of the named executive officer’s periodic review (which is conducted by the Chief Executive Officer or his designee for each of the other named executive officers and by the compensation committee for the Chief Executive Officer), and based on the compensation committee’s subjective assessment of the Company’s overall performance during the evaluation period.

(2) Annual Bonus Compensation

Historically, the board of directors has annually approved short-term incentive plans. In December 2016, our board of directors approved the 2017 short-term incentive plan (the “2017 STIP”), to motivate employees to drive outstanding company performance, provide flexibility given the uncertain business environment and improve employee retention. The executive officers were eligible to participate.

The 2017 incentives were based on the achievement of:

· Financial targets for Adjusted EBITDA;

· Safety performance as measured by our total recordable incident rate (“TRIR”); and

· Department key performance indicators (“KPIs”).

The 2017 STIP provided for a target award equal to 100% of base salary for Mr. Doss, 80% of base salary for Mr. Turner, 80% of base salary for Mr. Petersen, 60% of base salary for Mr. Harris and 60% of base salary for Ms. Thornton. The payout under the 2017 STIP was based 55% on the financial target, 20% on the safety target and 25% on department KPIs. The compensation committee set targets for each quarter of 2017, based on the recommendations of the Chief Executive Officer. The incentives were contingent upon the minimum threshold being achieved. Under the 2017 STIP, the formula for determining the potential payout percentage for a named executive officer’s financial target, was: (Actual Adjusted EBITDA—Minimum Threshold) / (Financial Goal—Minimum Threshold). If the financial goal was achieved, the payout percentage would be 100%. If the financial goal was exceeded, the payout percentage could reach a maximum of 200%.

The following targets were set each quarter:

First
Quarter 2017

Second
Quarter 2017

Third
Quarter 2017

Fourth
Quarter 2017

Minimum Threshold
(Adjusted EBITDA)

3.0 million

35 million

75 million

100 million

Financial Goal
(Adjusted EBITDA)

10.0 million

55 million

95 million

115 million

Safety Goal
(TRIR on a rolling 12-month basis)

0.50 or better

KPIs were determined by the manager of each named executive officer, except for Mr. Doss. The KPIs for Mr. Doss were determined by the board of directors. The 2017 STIP awards are paid out subsequent to the quarter for which the performance measures relate.

Under the terms of the 2017 STIP, the Chief Executive Officer was delegated the authority to award amounts above the maximum payout based on the individual performance of and contribution by the named executive officer. Such additional payouts are in the discretion of the Chief Executive Officer. Each named executive officer, other than the Chief Executive Officer, received a discretionary payment in excess of the maximum award.

The 2017 Compensation Table Summary below includes the payouts to the named executive officers under the 2017 STIP.

(3) Discretionary Bonus

The compensation committee retains discretion to grant bonus compensation to the named executive officers and other employees of the Company outside of the Bonus Plan. From time to time the Company may award discretionary annual bonuses to the named executive officers and may agree, in hiring or promoting a named executive officer, to a target bonus opportunity, expressed as a percentage of base salary or otherwise, in any case, to be paid only if the Company determines that the Company has attained its financial performance goals or other objectives. The Company has entered into retention bonus agreements with two of the named executive officers, Mr. Turner and Ms. Thornton. Pursuant to the terms of their respective retention bonus agreements, during 2017,

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Purpose. The purpose of the 2018 Plan is to attract and retain officers, employees, directors, consultants and other key personnel and to provide those persons incentives and awards for performance.

Administration; Effectiveness. The 2018 Plan will generally be administered by the compensation committee of our board of directors. The compensation committee has the authority to determine eligible participants in the 2018 Plan, and to interpret and make determinations under the 2018 Plan. Any interpretation or determination by the compensation committee under the 2018 Plan will be final and conclusive. The compensation committee may delegate all or any part of its authority under the 2018 Plan to any subcommittee thereof, and may delegate its administrative duties or powers to one or more of our officers, agents or advisors.

Shares Available for Awards under the 2018 Plan. Subject to adjustment as described in the 2018 Plan, the number of shares of our common stock available for awards under the 2018 Plan is 2,823,095, plus any shares of our common stock that become available under the 2018 Plan as a result of forfeiture, cancellation, expiration, or cash settlement of awards (the “Available Shares”), with such shares subject to adjustment to reflect any split or combination of our common stock. The Available Shares may be shares of original issuance, treasury shares or a combination of the foregoing.

The 2018 Plan also contains the following customary limits: (1) calendar year limits relating to the grant of stock options and stock appreciation rights and for restricted stock, restricted stock units, performance shares and/or other stock-based awards that are performance-based awards intended to satisfy the requirements for “qualified performance-based compensation” under Section 162(m) of the Code, or Qualified Performance-Based Awards; and (2) limits on the aggregate maximum value that a participant may receive in respect of an award of performance units and/or other awards payable in cash that are Qualified Performance-Based Awards, or a cash incentive award that is a Qualified Performance-Based Award in any calendar year.

Share Counting. The aggregate number of shares of our common stock available for award under the 2018 Plan will be reduced by one share of our common stock for every one share of our common stock subject to an award granted under the 2018 Plan.

The following shares of our common stock will be added (or added back, as applicable) to the aggregate number of shares of our common stock available under the 2018 Plan: (1) shares subject to an award that is cancelled or forfeited, expires or is settled for cash (in whole or in part); (2) shares of our common stock withheld by us in payment of the exercise price of a stock option granted under the 2018 Plan; (3) shares of our common stock tendered or otherwise used in payment of the exercise price of a stock option granted under the 2018 Plan; (4) shares of our common stock withheld by us or tendered or otherwise used to satisfy a tax withholding obligation; provided, however, that with respect to restricted stock, this provision will only be in effect until the ten-year anniversary of the date the 2018 Plan is approved by our stockholders; and (5) shares of our common stock subject to an appreciation right granted under the 2018 Plan that are not actually issued in connection with the settlement of such appreciation right. In addition, if under the 2018 Plan a participant has elected to give up the right to receive compensation in exchange for shares of our common stock based on fair market value, such shares of our common stock will not count against the aggregate number of shares of our common stock available under the 2018 Plan.

Shares of our common stock issued or transferred pursuant to awards granted under the 2018 Plan in substitution for or in conversion of, or in connection with the assumption of, awards held by awardees of an entity engaging in a corporate acquisition or merger with us or any of our subsidiaries, or substitute awards, will not count against, nor otherwise be taken into account in respect of, the share limits under the 2018 Plan. Additionally, shares of common stock available under certain plans that we or our subsidiaries may assume in connection with corporate transactions from another entity may be available for certain awards under the 2018 Plan, but will not count against, nor otherwise be taken into account in respect of, the share limits under the 2018 Plan.

Types of Awards Under the 2018 Plan. Pursuant to the 2018 Plan, we may grant restricted stock units, restricted stock, stock options (including incentive stock options as defined in Section 422 of the Code, or Incentive Stock Options), appreciation rights, cash incentive awards, performance shares, performance units, and certain other awards based on or related to shares of our common stock.

Each grant of an award under the 2018 Plan will be evidenced by an award agreement or agreements, which will contain such terms and provisions as the compensation committee may determine, consistent with the 2018 Plan. Those terms and provisions include the number of our shares of our common stock subject to each award, vesting terms and provisions that apply upon events such as retirement, death or disability of the participant or in the event of a change in control. A brief description of the types of awards which may be granted under the 2018 Plan is set forth below.

Restricted Stock Units. Restricted stock units awarded under the 2018 Plan constitute an agreement by us to deliver shares of our common stock, cash, or a combination thereof, to the participant in the future in consideration of the performance of services, but subject to the fulfillment of such conditions (which may include the achievement of management objectives) during the

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restriction period as the compensation committee may specify. Each grant or sale of restricted stock units may be made without additional consideration or in consideration of a payment by the participant that is less than the fair market value of shares of our common stock on the date of grant. During the restriction period applicable to restricted stock units, the participant will have no right to transfer any rights under the award and will have no rights of ownership in the shares of our common stock underlying the restricted stock units and no right to vote them. Rights to dividend equivalents may be extended to and made part of any restricted stock unit award at the discretion of and on the terms determined by the compensation committee. Each grant of restricted stock units will specify that the amount payable with respect to such restricted stock units will be paid in cash, shares of our common stock, or a combination of the two.

Restricted Stock. Restricted stock constitutes an immediate transfer of the ownership of shares of our common stock to the participant in consideration of the performance of services, entitling such participant to dividend, voting and other ownership rights, subject to the substantial risk of forfeiture and restrictions on transfer determined by the compensation committee for a period of time determined by the compensation committee or until certain management objectives specified by the compensation committee are achieved. Each such grant or sale of restricted stock may be made without additional consideration or in consideration of a payment by the participant that is less than the fair market value per share of our common stock on the date of grant.

Any grant of restricted stock may specify the treatment of dividends or distributions paid on restricted stock that remains subject to a substantial risk of forfeiture.

Stock Options. Stock options granted under the 2018 Plan may be either Incentive Stock Option or non-qualified stock options Incentive Stock Options. Except with respect to substitute awards, Incentive Stock Options and non-qualified stock options must have an exercise price per share that is not less than the fair market value of a share of our common stock on the date of grant. The term of a stock option may not extend more than ten years after the date of grant.

Each grant will specify the form of consideration to be paid in satisfaction of the exercise price.

Appreciation Rights. The 2018 Plan provides for the grant of appreciation rights. An appreciation right is a right to receive from us an amount equal to 100%, or such lesser percentage as the compensation committee may determine, of the spread between the base price and the value of shares of our common stock on the date of exercise.

An appreciation right may be paid in cash, shares of our common stock or any combination thereof. Except with respect to substitute awards, the base price of an appreciation right may not be less than the fair market value of a common share on the date of grant. The term of an appreciation right may not extend more than ten years from the date of grant.

Cash Incentive Awards, Performance Shares, and Performance Units. Performance shares, performance units and cash incentive awards may also be granted to participants under the 2018 Plan. A performance share is a bookkeeping entry that records the equivalent of one share of our common stock, and a performance unit is a bookkeeping entry that records a unit equivalent to $1.00 or such other value as determined by the compensation committee. Each grant will specify the number or amount of performance shares or performance units, or the amount payable with respect to cash incentive awards, being awarded, which number or amount may be subject to adjustment to reflect changes in compensation or other factors.

These awards, when granted under the 2018 Plan, become payable to participants upon of the achievement of specified management objectives and upon such terms and conditions as the compensation committee determines at the time of grant. Each grant may specify with respect to the management objectives a minimum acceptable level of achievement and may set forth a formula for determining the number of performance shares or performance units, or the amount payable with respect to cash incentive awards, that will be earned if performance is at or above the minimum or threshold level, or is at or above the target level but falls short of maximum achievement. Each grant will specify the time and manner of payment of cash incentive awards, performance shares of performance units that have been earned, and any grant may further specify that any such amount may be paid or settled in cash, shares of our common stock, restricted stock, restricted stock units or any combination thereof. Any grant of performance shares may provide for the payment of dividend equivalents in cash or in additional shares of our common stock.

Other Awards. The compensation committee may grant such other awards that may be denominated or payable in, valued in whole or in part by reference to, or otherwise based on, or related to, shares of our common stock or factors that may influence the value of such shares of our common stock, including, without limitation, convertible or exchangeable debt securities, other rights convertible or exchangeable into shares of our common stock, purchase rights for shares of our common stock, awards with value and payment contingent upon our performance of specified subsidiaries, affiliates or other business units or any other factors designated by the compensation committee, and awards valued by reference to the book value of the shares of our common stock or the value of securities of, or the performance of our subsidiaries, affiliates or other business units.

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Adjustments; Corporate Transactions. The compensation committee will make or provide for such adjustments in the: (1) number of shares of our common stock covered by outstanding stock options, appreciation rights, restricted stock, restricted stock units, performance shares and performance units granted under the 2018 Plan; (2) if applicable, number of shares of our common stock covered by other awards granted pursuant to the 2018 Plan; (3) exercise price or base price provided in outstanding stock options and appreciation rights; (4) kind of shares covered thereby; (5) cash incentive awards; and (6) other award terms, as the compensation committee determines to be equitably required in order to prevent dilution or enlargement of the rights of participants that otherwise would result from (a) any stock dividend, stock split, combination of shares, recapitalization or other change in our capital structure, (b) any merger, consolidation, spin-off, spin-out, split-off, split-up, reorganization, partial or complete liquidation or other distribution of assets, issuance of rights or warrants to purchase securities or (c) any other corporate transaction or event having an effect similar to any of the foregoing.

In the event of any such transaction or event, or in the event of a change in control (as defined in the 2018 Plan), the compensation committee may provide in substitution for any or all outstanding awards under the 2018 Plan such alternative consideration (including cash), if any, as it may in good faith determine to be equitable under the circumstances and will require in connection therewith the surrender of all awards so replaced in a manner that complies with Section 409A of the Code. In addition, for each stock option or appreciation right with an exercise price greater than the consideration offered in connection with any such transaction or event or change in control, the compensation committee may in its discretion elect to cancel such stock option or appreciation right without any payment to the person holding such stock option or appreciation right. The compensation committee will make or provide for such adjustments to the numbers and kind of shares available for issuance under the 2018 Plan and the share limits of the 2018 Plan as the compensation committee in its sole discretion may in good faith determine to be appropriate in connection with such transaction or event. However, any adjustment to the limit on the number of shares of our common stock that may be issued upon exercise of Incentive Stock Options will be made only if, and to the extent, such adjustment would not cause any option intended to qualify as an Incentive Stock Option to fail to so qualify.

Transferability of Award. Except as otherwise provided by the compensation committee, no stock option, appreciation right, restricted share, restricted stock unit, performance share, performance unit, cash incentive award, other award or dividend equivalents paid with respect to awards made under the 2018 Plan may be transferred by a participant.

Amendment and Termination of the 2018 Plan. Our board of directors generally may amend the 2018 Plan from time to time, in whole or in part. However, if any amendment (1) would materially increase the benefits accruing to participants under the 2018 Plan, (2) would materially increase the number of shares of our common stock which may be issued under the 2018 Plan, (3) would materially modify the requirements for participation in the 2018 Plan, or (4) must otherwise be approved by our stockholders in order to comply with applicable law or the rules of the NYSE, then such amendment will be subject to stockholder approval and will not be effective unless and until such approval has been obtained.

Our board of directors may, in its discretion, terminate the 2018 Plan at any time. Termination of the 2018 Plan will not affect the rights of participants or their successors under any awards outstanding and not exercised in full on the date of termination. No grant will be made under the 2018 Plan more than ten years after the effective date of the 2018 Plan, but all grants made on or prior to such date shall continue in effect thereafter subject to the terms of the 2018 Plan.

The restricted stock units will be settled in shares of our common stock subject to the discretion of the compensation committee to settle the restricted stock units in cash. Most of the shares authorized under the 2018 Plan were issued in connection with the IPO.

(5) Perquisites

Other than as disclosed below, during our fiscal year ended December 31, 2017, our executives did not receive any perquisites and were not entitled to benefits that are not otherwise available to all of our employees.

(6) General Benefits

The following are standard benefits offered to all eligible Company employees, including the executive officers.

Retirement Benefits. The Company offers a 401(k) defined contribution retirement plan for all eligible employees, including the named executive officers, known as the FTS International, Inc. 401(k) Plan (the “401(k) Plan”). The 401(k) is a voluntary contributory plan, which allows a participant to defer, by payroll deductions, from 0% to 100% of the participant’s annual compensation, limited to certain annual maximums set by the Code. The 401(k) Plan has historically provided a discretionary matching contribution to each participant’s account. The Company suspended matching contributions in July 2015 and resumed making contributions in July 2017. Each named executive officer received a matching contribution from the Company during 2017;

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however, such amounts, together with all other perquisites, were less than $10,000 in the aggregate per named executive officer. Consequently, such amounts are not reflected in the 2017 Summary Compensation Table.

Health and Welfare Benefits. The Company makes available medical, dental, vision, prescription drug, flexible spending accounts, health savings accounts, life insurance, and disability coverage to all active eligible employees, including the named executive officers.

Paid Time-Off Benefits. The Company provides paid time off, bereavement leave, maternity leave, and other paid holidays to all employees, including the named executive officers.

2017 Summary Compensation Table

The following table summarizes the compensation of our principal executive officer, principal financial officer, and three most highly compensated executive officers other than the principal executive officer and principal financial officer, during the years ended December 31, 2015, 2016 and 2017.

Name and Principal Position	Year	Salary		Bonus (1)(2)(3)(4)		Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation (5)		Nonqualified Deferred Compensation Earnings		All Other Compensation (6)		Total ($)
(a)	(b)	(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)
Michael J. Doss	2017	$	623,077	$	—	$	—	$	—	$	1,290,000	$	—	$	—	$	1,913,077
Chief Executive Officer	2016	$	500,000	$	60,000	$	—	$	—	$	—	$	—	$	—	$	560,000
	2015	$	397,500	$	—	$	—	$	—	$	—	$	—	$	13,260	$	410,760

Lance Turner	2017	$	285,192	$	40,000	$	—	$	—	$	460,000	$	—	$	—	$	785,192
Chief Financial Officer and Treasurer	2016	$	245,000	$	30,000	$	—	$	—	$	—	$	—	$	—	$	275,000
	2015	$	206,154	$	—	$	—	$	—	$	—	$	—	$	12,030	$	218,184

Buddy Petersen	2017	$	442,308	$	—	$	—	$	—	$	750,000	$	—	$	—	$	1,192,308
Chief Operating Officer	2016	$	350,000	$	40,000	$	—	$	—	$	—	$	—	$	—	$	390,000
	2015	$	158,077	$	—	$	—	$	—	$	—	$	—	$	—	$	158,177

Perry A. Harris	2017	$	350,000	$	140,000	$	—	$	—	$	441,000	$	—	$	—	$	931,000
Senior Vice President, Commercial	2016	$	320,000	$	79,000	$	—	$	—	$	—	$	—	$	—	$	399,000
	2015	$	313,846	$	32,000	$	—	$	—	$	—	$	—	$	13,175	$	359,021

Karen Thornton	2017	$	259,054	$	58,570	$	—	$	—	$	300,000	$	—	$	—	$	617,624
Chief Administrative Officer	2016	$	210,853	$	46,714	$	—	$	—	$	—	$	—	$	—	$	257,567
	2015	$	233,567	$	—	$	—	$	—	$	—	$	—	$	15,520	$	249,087

(1) With respect to Mr. Harris, for 2015, column (d) includes a retention bonus payment equal to 10% of Mr. Harris’ base salary pursuant to the terms of his employment agreement.

(2) For the fiscal year 2016, our board of directors approved a cash bonus pool amount to be paid as discretionary bonuses. Our board of directors delegated authority to allocate the bonus pool to our chief executive officer in his sole discretion. These discretionary bonuses were paid in recognition of each of the named executive officers’ contributions to the Company’s cost reduction initiatives.

(3) With respect to Messrs. Doss, Turner and Petersen, for 2016, the amount set forth in column (d) represents the discretionary bonuses paid pursuant to the cash bonus pool. With respect to Mr. Harris, for 2016, column (d) includes a retention bonus payment equal to 20% of Mr. Harris’ base salary pursuant to the terms of his employment agreement. With respect to Ms. Thornton, for 2016, column (d) includes a discretionary bonus equal to $15,000 pursuant to the discretionary bonus pool, a performance bonus equal to $20,000 and a retention bonus equal to $11,714 pursuant to the terms of her retention bonus agreement dated December 19, 2016.

(4) With respect to Mr. Turner, for 2017, the amount set forth in column (d) represents a retention bonus paid pursuant to the terms of a retention bonus agreement, dated August 5, 2015, which entitled Mr. Turner to a retention bonus equal to $40,000 payable upon the Company’s achievement of the pre-determined Adjusted EBITDA thresholds. With respect to Mr. Harris, for 2017, column (d) includes a retention bonus payment equal to 40% of Mr. Harris’ base salary in 2017 pursuant to the terms of his employment agreement. With respect to Ms. Thornton, for 2017, column (d) includes a retention bonus payment equal to 25% of Ms. Thornton’s base salary in 2015 pursuant to the terms of her retention bonus agreement dated March 29, 2017.

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(5) With respect to all named executive officers, for 2017, the amount set forth in column (g) represents payments made under the Company’s 2017 Short Term Incentive Plan. For additional information, see “—Short Term Incentive Plans—2017 Short Term Incentive Plan” in this Item 11. The payments under the 2017 STIP were made to all named executive officers on or before January 12, 2018.

(6) See the All Other Compensation Table for additional information.

All Other Compensation Table

Name and Principal Position	Year	Company Matching Contributions to 401(k) Plan (1)		Other Perquisites and Benefits (2)		Total (3)(4)

Michael J. Doss	2017	$	—	$	—	$	—
Chief Executive Officer	2016	$	—	$	—	$	—
	2015	$	13,073	$	187	$	13,260

Lance Turner	2017	$	—	$	—	$	—
Chief Financial Officer and Treasurer	2016	$	—	$	—	$	—
	2015	$	11,862	$	168	$	12,030

Buddy Petersen	2017	$	—	$	—	$	—
Chief Operating Officer	2016	$	—	$	—	$	—
	2015	$	—	$	—	$	—

Perry A. Harris	2017	$	—	$	—	$	—
Senior Vice President, Commercial	2016	$	—	$	—	$	—
	2015	$	9,600	$	3,575	$	13,175

Karen Thornton	2017	$	—	$	—	$	—
Chief Administrative Officer	2016	$	—	$	—	$	—
	2015	$	15,340	$	280	$	15,620

(1) This column represents the matching contributions made by the Company for the benefit of named executive officers under the 401(k) Plan. The 401(k) Plan is discussed in more detail in the “Elements of Compensation” in this Item 11.

(2) This column represents the value of other benefits provided to the named executive officers in 2015 and includes premiums for life insurance policies for each named executive officer in which the Company is not the beneficiary. In addition, the amount for Mr. Harris reflects the value associated with Mr. Harris’ personal use of a corporate vehicle.

(3) With respect to Mr. Petersen, for 2015, the perquisites and other personal benefits were in the aggregate less than $10,000.

(4) For 2016 and 2017 the perquisites and other personal benefits were in the aggregate less than $10,000 for each named executive officer.

Grants of Plan-Based Awards

The following table reflects each grant of an award made to a named executive officer during fiscal year 2017 under any plan.

		Estimated future payouts under non-equity incentive plan awards (1)(2)			Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Stock Awards: Number of Shares or Units	All Other Option Awards: Number of Securities Underlying	Grant Date Fair Value of
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)(3)	Threshold (#)	Target (#)	Maximum (#)	of Stock (#)	Options (#)	Stock Awards(5)($)
Michael J. Doss	N/A	0	650,000	1,300,000	—	—	—	—	—	—
Lance Turner	N/A	0	229,000	458,000	—	—	—	—	—	—

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		Estimated future payouts under non-equity incentive plan awards (1)(2)			Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Stock Awards: Number of Shares or Units	All Other Option Awards: Number of Securities Underlying	Grant Date Fair Value of
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)(3)	Threshold (#)	Target (#)	Maximum (#)	of Stock (#)	Options (#)	Stock Awards(5)($)
Buddy Petersen	N/A	0	370,000	740,000	—	—	—	—	—	—
Perry A. Harris	N/A	0	198,300	396,600	—	—	—	—	—	—
Karen Thornton	N/A	0	142,585	285,171	—	—	—	—	—	—

(1) Amounts shown in these columns represent each named executive officer’s non-discretionary incentive bonus opportunity under the 2017 STIP in which such named executive officers participated. The “Target” amount represents the named executive officer’s target bonus if the performance goals under the 2017 STIP was achieved at the target level. The “Threshold” amount represents named executive officer’s minimum bonus if the performance goal under the bonus program was achieved at the minimum level. The “Maximum” amount represents the named executive officer’s target bonus if the performance goals under the 2017 STIP was achieved at the Maximum level.

(2) The 2017 STIP provided for quarterly targets, based on the recommendations of the Chief Executive Officer. The amounts reflected in each column reflects the Threshold, Target and Maximum, aggregated for each of the four quarters occurring in 2017.

(3) Under the terms of the 2017 STIP, the Chief Executive Officer was delegated the authority to award amounts above the Maximum payout based on the individual performance of and contribution by the named executive officer. Such additional payouts are in the discretion of the Chief Executive Officer. Each named executive officer, other than the Chief Executive Officer, received a discretionary payment in excess of the Maximum award.

Summary of Employment Agreements

It is the Company’s general philosophy that all of the Company’s employees should be “at will” employees, thereby allowing both the Company and the employee to terminate the employment relationship at any time and without restriction or financial obligation, with limited exceptions.

We have not entered into employment agreements with any of our executive officers, other than Perry Harris. We entered into an employment agreement with Mr. Harris in December 2014 in connection with our acquisition of the assets of J-W Wireline Company. Our agreement with Mr. Harris had a term of three years and expired on December 6, 2017. The Company has no continuing obligations to Mr. Harris following the expiration of his employment agreement.

The employment agreement with Mr. Harris provided for a base salary of not less than $320,000 per year. Mr. Harris was also eligible to participate in any short-term incentive plan and in any long-term incentive plan with an annual target award percentage under each plan equal to or exceeding 40% of his base salary. Despite the expiration of the employment agreement, Mr. Harris continues to be subject to non-solicitation, confidentiality and non-compete provisions, which remain effective during Mr. Harris’ employment and continue for a period of one year following the termination of Mr. Harris’ employment.

Mr. Harris was also entitled to retention bonuses equal to 10%, 20% and 40% of his annual base salary set forth in the employment agreement upon his completion of one, two and three years of service, respectively, with the Company and subject to meeting certain performance criteria. Each retention bonus was payable in installments in the calendar year following the applicable service anniversary.

Additionally, if Mr. Harris’ employment had been terminated before the end of the three year term:

· due to death or disability, he would have received earned but unpaid compensation, any unpaid short-term incentive plan compensation for the calendar year ending before his termination, a prorated amount of his target short-term incentive plan compensation for the portion of the year he was employed and any earned but unpaid retention bonus;

· by us without cause or by him for good reason (each as defined in his employment agreement), he would have received earned but unpaid compensation, his base salary through the one-year anniversary of the termination and the average of his short-term incentive plan compensation paid or payable for the prior three years or the average of his short-term

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incentive plan compensation for the number of years during which he was eligible to participate in the short-term incentive plan if less than three and any earned but unpaid retention bonus;

· by us for cause or by him without good reason, he would have received earned but unpaid compensation and if the termination is by him without good reason and occurs after the third anniversary of the date of the agreement, he would have received earned but unpaid retention bonus; and

· by us without cause or by him for good reason within two years after a change of control (as defined in his employment agreement) occurred, he would have received earned but unpaid compensation and a lump sum cash payment equal to the sum of (1) his base salary at the highest annual rate in effect on or before his termination and (2) an amount equal to the greater of (a) the average of his short-term incentive compensation paid or payable had he remained employed for the prior three full fiscal years ending before the date of termination, or the average of his short-term incentive plan compensation for the number of years during which he was eligible to participate in the short-term incentive plan if less than three; (b) the short-term incentive plan compensation paid to him for the last full fiscal year of his employment; and (c) his target short-term incentive plan compensation for the fiscal year that includes the date of termination.

All of the severance payments described above were subject to Mr. Harris’ execution of a release of claims and compliance with the non-solicitation, confidentiality and non-compete provisions of the employment agreement.

Outstanding Equity Awards at Fiscal Year-End

The following table reflects outstanding equity awards as of December 31, 2017, for each of the named executive officers, which is limited to outstanding equity awards issued under our 2014 LTIP. The numbers below are before adjusting for our 69.258777:1 reverse stock split that occurred on February 1, 2018.

	Option Awards				Stock Awards
	Number of	Number of				Market
	Securities	Securities			Number of	Value of
	Underlying	Underlying			Shares of	Shares of
	Unexercised	Unexercised	Option		Stock that	Stock that
	Options	Options	Exercise	Option	Have Not	Have Not
	(Exercisable)	(Unexercisable)	Price	Expiration	Vested	Vested
Name	(#)	(#)	($)	Date	(#)	($)(1)(2)
Michael J. Doss	—	—	—	—	880,207	$	228,761
Buddy Petersen	—	—	—	—	—	—
Perry A. Harris	—	—	—	—	133,332	$	34,652
Lance Turner	—	—	—	—	167,500	$	43,532
Karen Thornton	—	—	—	—	468,750	$	121,826

(1) The market value is based upon the initial public offering price of $18.00 per share.

(2) The restricted stock units vested immediately before effectiveness of the registration statement on February 1, 2018, and settled in cash.

Option Exercises and Stock Vested Table

During the fiscal year ended December 31, 2017, no stock options, stock appreciation rights or similar instruments were exercised by any named executive officer. During the fiscal year ended December 31, 2017, no restricted stock, restricted stock units or similar instruments, held by any named executive officer, vested.

No Pension Benefits

Aside from our 401(k) Plan, we do not maintain any pension plan or arrangement under which our named executive officers are entitled to participate or receive post-retirement benefits.

No Nonqualified Deferred Compensation

The Company does not maintain any defined contribution or other plan that provides for the deferral of compensation on a basis that is not tax-qualified.

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Potential Payments Upon Termination or Change in Control

We have entered into severance agreements with Messrs. Doss, Turner, and Petersen that provide for payments to be made to the respective named executive officer in connection with a termination of employment. These agreements have an initial term of one-year that expired on May 3, 2017. The severance agreements were extended on June 15, 2017 for an additional one-year period, and now expire on May 3, 2018. Each of Messrs. Doss and Petersen is eligible to receive a lump sum equal to 1.5 times his then-current annual base salary as severance following his termination of employment by us without cause (as defined in the agreement), or by the executive for good reason (as defined in the agreement), subject to his execution of a release of claims and compliance with the non-solicitation, confidentiality and non-compete provisions in his severance agreement and under any other agreement to which the Company (or any of its affiliates) and such executive are a party. Mr. Turner is eligible to receive a lump sum equal to 1.0 times his then-current annual base salary as severance following his termination of employment by us without cause (as defined in the agreement), or by the executive for good reason (as defined in the agreement), subject to his execution of a release of claims and compliance with the non-solicitation, confidentiality and non-compete provisions in the severance agreements and under any other agreement to which the Company (or any of its affiliates) and Mr. Turner are a party.

Named Executive Officer	Termination by the Company without Cause		Termination by Executive For Good Reason
Michael J. Doss	$	1,125,000	$	1,125,000
Buddy Petersen	$	750,000	$	750,000
Lance Turner	$	300,000	$	300,000

On June 15, 2017 we entered into a retention agreement with Ms. Thornton. The agreement provided that Ms. Thornton will receive a retention bonus equal to $108,000 and is payable on June 15, 2018, subject to Ms. Thornton’s continued employment with the Company through the bonus payment date. If Ms. Thornton is terminated by us without cause or the Company completes a sale of a majority of its equity or substantially all of its assets, Ms. Thornton is entitled to the payment of the full retention bonus, subject to her execution of a release of claims.

DIRECTOR COMPENSATION

During the fiscal year ended December 31, 2017, the Company did not pay any compensation to our directors, but generally reimbursed our directors for reasonable out-of-pocket expenses that they incurred in connection with their service as directors, in accordance with our general expense reimbursement policies. Each director is fully indemnified by us, pursuant to individual indemnification agreements entered into on February 1, 2018 and the certificate of incorporation, for actions associated with being a director to the fullest extent permitted under Delaware law.

We believe that attracting and retaining qualified non-employee directors will be critical to our future growth. As such, the Company expects that it will provide compensation that is comparable to the compensation that is offered to directors of companies that are similar to ours, including equity-based compensation, in the future. Currently, the Company reimburses our independent directors for reasonable out-of-pocket expenses that they incur in connection with their service as directors, in accordance with our general expense reimbursement policies.

Change in Control or Other Arrangements

Except for the foregoing, and the arrangements described above with Mr. Doss, there are no other arrangements for compensation of directors and there are no employment contracts between the Company and its directors or any change in control arrangements. See “Potential Payments Upon Termination or Change in Control” in this Item 11 for information regarding arrangements with Mr. Doss.

Outstanding Equity Awards at Fiscal Year End.

The Company did not have any outstanding equity awards at the end of its fiscal year ended December 31, 2017 and did not have any equity compensation plans in effect at the end of its fiscal year ended December 31, 2017 for directors. Mr. Doss’ equity awards described under “Outstanding Equity Awards at Fiscal Year-End” in this Item 11 relates to his service as an employee of the Company.

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NAME OF BENEFICIAL OWNER	SHARES BENEFICIALLY OWNED	PERCENT OF CLASS
Greater than 5% stockholders
Maju Investments (Mauritius) Pte Ltd (1)(2) c/o SGG Corporate Services (Mauritius) Ltd, 33, Edith Cavell Street, Port Louis, 11324, Republic of Mauritius	41,617,144	38.1	%
CHK Energy Holdings, Inc. (2)(3) CHK Energy Holdings, Inc. is 6100 N. Western Avenue, Oklahoma City, Oklahoma 73118	21,998,789	20.1	%
Senja Capital Ltd (4)(5)(6) Senja Capital Ltd is CCS Trustees Limited, 263 Main Street, P.O. Box 2196, Road Town, Tortola, British Virgin Islands	12,175,935	11.1	%
Hampton Asset Holding Ltd. (5)(7)(8) Hampton Asset Holding Ltd. is CCS Trustees Limited, 263 Main Street, P.O. Box 2196, Road Town, Tortola British Virgin Islands	1,164,291	1.1	%
Directors and Named Executive Officers
Michael J. Doss	10,000	*	%
Buddy Petersen	—	—
Lance Turner	4,500	*	%
Perry A. Harris	7,000	*	%
Goh Yong Siang	—	—
Domenic J. Dell’Osso, Jr. (9)	6,000	*	%
Bryan J. Lemmerman (9)	—	—
Ong Tiong Sin (10)	13,340,226	12.2	%
Boon Sim	50,000	*	%
Carol J. Johnson	2,000	*	%
Karen D. Thornton	—	—
All executive officers and directors as a group (12 persons)	13,419,726	12.3	%

* Represents beneficial ownership of less than one percent

(1) Maju Investments (Mauritius) Pte Ltd is wholly owned by Fullerton Fund Investments Pte Ltd, which is wholly owned by Temasek.

(2) On February 1, 2018, the Company entered into an investors’ rights agreement with Maju and Chesapeake. Pursuant to the investors’ rights agreement, Maju and Chesapeake may be deemed to have formed a group pursuant to Rule 13d-5(b)(1) of the Exchange Act. Such group could be deemed to have beneficial ownership, for purposes of Sections 13(d) and 13(g) of the Exchange Act, of all equity securities of the Company beneficially owned by such parties. Such parties would, as of March 7, 2018 be deemed to beneficially own an aggregate of 63,615,933 shares (58.2%) of our capital stock. Each stockholder party to the investors’ rights agreement disclaims beneficial ownership of any shares of our common stock owned by the other stockholder party to the agreement.

(3) CHK Energy Holdings, Inc. is a subsidiary of Chesapeake Energy Corporation.

(4) Senja Capital Ltd is wholly owned by RRJ Capital Master Fund I, L.P., the general partner of which is RRJ Capital Limited.

(5) On February 1, 2018 the Company entered into an investors’ rights agreement with Senja and Hampton. Pursuant to the investors’ rights agreement, Senja and Hampton may be deemed to have formed a group pursuant to Rule 13d-5(b)(1) of the Exchange Act. Such group could be deemed to have beneficial ownership, for purposes of Sections 13(d) and 13(g) of the Exchange Act, of all equity securities of the Company beneficially owned by such parties. Such parties would, as of March 7,

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2018 be deemed to beneficially own an aggregate of 13,340,226 shares (12.2%) of our capital stock. Each stockholder party to the investors’ rights agreement disclaims beneficial ownership of any shares of our common stock owned by the other stockholder party to the agreement.

(6) RRJ Capital Limited’s board of directors, consisting of Ong Tiong Sin, Ong Tiong Boon, Eddie Teh Ewe Guan, Rizal Bin Ishak and Kim Young So, exercises voting and investment power over these shares.

(7) Hampton Asset Holding Ltd. is wholly owned by Ong Tiong Sin.

(8) Ong Tiong Sin, sole shareholder and sole director of Hampton Asset Holding Ltd., has sole voting and investment power over these shares.

(9) Mr. Dell’Osso is the Executive Vice President and Chief Financial Officer of Chesapeake Parent, and Mr. Lemmerman is the Vice President—Business Development at Chesapeake Parent.

(10) Mr. Ong is the founder and Chief Executive Officer of RRJ Capital Limited, and sole shareholder and sole director of Hampton Asset Holding Ltd., and disclaims beneficial ownership of any shares owned directly or indirectly by Senja Capital Ltd, except to the extent of his pecuniary interest therein. As such, the shares attributed to Mr. Ong represent a sum of the shares beneficially owned by Senja Capital Ltd and Hampton Asset Holding Ltd.

Equity Compensation Plan Information

	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and right	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Plan Category	(a)		(b)	(c)
Equity compensation plans approved by stockholders	1,013,539	(1)	N/A(2)	0	(3)
Equity compensation plans not approved by stockholders	—		N/A	—

Total	1,013,539		N/A	0

(1) Includes an aggregate of restricted stock units that were not vested as of December 31, 2017 under the 2014 LTIP. The numbers are before adjustment for the 69.258777:1 reverse stock split that occurred in February 2018 prior to the IPO. The restricted stock units vested immediately before the effectiveness of the registration statement on February 1, 2018 and were settled in cash.

(2) Only restricted stock units have been granted under the 2014 LTIP; there is no weighted average exercise price associated with these awards.

(3) Represents shares of common stock authorized for issuance under the 2014 LTIP in connection with awards of stock options, share appreciation rights, restricted shares, restricted share units, performance shares, performance units, dividend equivalents and other share-based award.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The following is a summary of transactions that occurred on or were in effect after January 1, 2017 that we have been a party and which the amount involved exceeded $120,000 and in which any of our executive officers, directors or beneficial holders of more than 5% of our capital stock had or will have a direct or indirect material interest.

Transactions with Chesapeake

Chesapeake is one of our largest stockholders and is a wholly owned subsidiary of one of our customers, Chesapeake Parent. We recognized revenue from Chesapeake Parent for well-completion services in the amount of $32.1 million, $2.5 million and $113.1 million for the years ended December 31, 2015, 2016 and 2017, respectively.

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We are party to a master service agreement dated July 9, 2012, and a master commercial agreement dated December 24, 2016, with subsidiaries of Chesapeake Parent. These agreements govern the performance of services and the supply of materials or equipment to Chesapeake Parent, the specific terms of which are addressed in subsequent written purchase or work orders. These agreements contain standard terms and provisions, including insurance requirements and confidentiality obligations and allocates certain operational risks through indemnity provisions.

Stockholders Agreement

In September 2012, we entered into an amended and restated stockholders agreement with Maju, Senja, Chesapeake, and other stockholders party thereto, as amended in November 2012, April 2014, June 2015, November 2015 and September 2016. The amended and restated stockholders agreement contains agreements among our stockholders regarding, among other things, transfer restrictions, tag along rights, drag along rights, right of first offer, preemptive rights and director nomination and information rights. Prior to completion of the IPO, the amended and restated stockholders agreement was terminated.

Investors’ Rights Agreements

On February 1, 2018, the Company entered into an investors’ rights agreement with Maju and Chesapeake, pursuant to which we will be required to take all necessary action for individuals designated by Maju and Chesapeake to be included in the slate of nominees recommended by the board of directors for election by our stockholders. Under the investors’ rights agreement, each of Maju and Chesapeake have the right to nominate (1) two directors so long as it beneficially owns at least 15% of our then-outstanding shares of capital stock or (2) one director so long as it beneficially owns at least 5% but less than 15% of our then-outstanding shares of capital stock. The investors’ rights agreement also provides that so long as Maju or Chesapeake beneficially owns at least 5% of our then-outstanding shares of capital stock, it may elect to designate one non-voting observer to attend all meetings of the board of directors and committees of the board of directors. The investors’ rights agreement also provides Maju or Chesapeake with certain information rights for so long as it beneficially owns at least 5% of our then-outstanding shares of common stock. Each of Maju and Chesapeake have agreed to take all reasonable actions, including voting or providing a consent or proxy, to ensure the election of their respective nominees and other terms of the investors’ rights agreement.

Under the investors’ rights agreement, Maju and Chesapeake may designate its nominee director to be a member of each committee, subject to compliance with applicable stock exchange requirements. The investors’ rights agreement restricts our ability to adopt a shareholder rights plan and similar arrangements or to become subject to the provisions of Section 203 of the DGCL without the consent of Maju and Chesapeake. The agreement also grants other consent rights to Maju and Chesapeake, including for charter and bylaw provisions inconsistent with the investors’ rights agreement.

The investors’ rights agreement with Maju and Chesapeake provides that (1) we renounce any interest in any business opportunities of Chesapeake and Maju, their affiliates and directors nominated by them, and that none of the foregoing have any obligation to offer or present us those opportunities or any related information or to use any information regarding other or competing business for us, (2) we acknowledge our prior and future agreements and transactions with Chesapeake and its affiliates and (3) we waive any claims or recourse relating to the foregoing matters.

On February 1, 2018, the Company entered into an investors’ rights agreement with Senja and Hampton, pursuant to which, the Company is required to take all necessary action for the individual collectively designated by Senja and Hampton to be included in the slate of nominees recommended by the board of directors for election by our stockholders. Under the investors’ rights agreement, Senja and Hampton have the right to nominate one director so long as they collectively with their affiliates own at least 5% of our then-outstanding shares of capital stock. The investors’ rights agreement also provides that so long as Senja and Hampton collectively with their affiliates own at least 5% of our then-outstanding shares of capital stock, they may elect to designate one non-voting observer to attend all meetings of the board of directors and committees of the board of directors. The investors’ rights agreement also provides Senja and Hampton with certain information rights for so long as they collectively with their affiliates own at least 5% of our then-outstanding shares of capital stock. The agreement also grants other rights to Senja and Hampton, including consent rights for charter and bylaw provisions inconsistent with the investors’ rights agreement.

The investors’ rights agreement with Senja and Hampton will provide that (1) we renounce any interest in any business opportunities of Senja and Hampton, their affiliates and directors nominated by them, and that none of the foregoing have any obligation to offer or present us those opportunities or any related information or to use any information regarding other or competing business for us and (2) we waive any claims or recourse relating to the foregoing matters.

Senja is wholly owned by RRJ Capital Master Fund I, L.P. RRJ is the general partner of RRJ Capital Master Fund I, L.P. RRJ’s board of directors, which consists of Ong Tiong Sin, Ong Tiong Boon, Eddie Teh Ewe Guan, Rizal Bin Ishak and Kim Young

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So, exercises voting and investment power over our shares held by Senja. Further, Mr. Ong, Senja’s board designee on our board of directors is also the sole shareholder and sole director of Hampton.

Registration Rights Agreement

On February 1, 2018, the Company entered into a registration rights agreement with Maju, Chesapeake, Senja and Hampton. Under the terms of the registration rights agreement, the parties may request registration, or a demand registration, of all or a portion of their common stock, or Registrable Shares, under the Securities Act. We will not be obligated to effectuate more than four demand registrations for each of Maju and Chesapeake, and more than four demand registrations for Senja and Hampton collectively. Any demand registration must be for an anticipated aggregate offering price of at least $50.0 million. In addition, in the event we register additional shares of common stock for sale to the public, we will be required to give notice of the registration to the parties to the registration rights agreement and, subject to certain limitations, include shares of common stock held by them in the registration. The agreement includes customary indemnification and contribution provisions in favor of the parties to the agreement against certain losses and liabilities arising out of or based upon any filing or other disclosure made by us under securities laws relating to such registration. In addition, each stockholder that has registration rights pursuant to this agreement will agree not to sell, otherwise dispose of any securities, or exercise registration rights without the prior written consent of the underwriters for a period of 180 days after the date of the IPO, subject to certain customary exceptions, terms and conditions. We will generally pay all registration expenses in connection with our registration obligations.

Procedures for Approval of Related Party Transactions

Pursuant to our amended and restated audit committee charter, our audit committee has the primary responsibility for reviewing and approving or disapproving “related-party transactions,” which are transactions between us and related persons in which the aggregate amount involved exceeds or may be expected to exceed $120,000 and in which a related person has or will have a direct or indirect material interest. Our policy regarding transactions between us and related persons provides that the definition of a related person will include, among others, a director, executive officer, nominee for director or greater than 5% beneficial owner of our common stock, in each case since the beginning of the most recently completed fiscal year, and any of their immediate family members. We have not adopted formal policies and procedures for the review, approval or disapproval of such transactions, but instead review them on a case-by-case basis and will follow the guidance of Section 144 of the Delaware General Corporation Law.

Item 14. Principal Accountant Fees and Services

The following table represents aggregate fees billed to us for the fiscal years ended December 31, 2017 and 2016 by our independent registered public accounting firm, Grant Thornton LLP. All such fees described below were approved by the audit committee.

	2017		2016
Audit fees (1)	$	789,780	$	473,608
Audit-related fees (2)	$	0	$	0
Tax fees (3)	$	0	$	0
All other fees (4)	$	0	$	0

Total fees	$	789,780	$	473,608

(1) Audit fees consist of aggregate fees for professional services rendered for the audit of our consolidated financial statements, reviews of our interim consolidated financial statements, services in connection with statutory and regulatory filing requirements and our debt and equity offerings.

(2) Audit-related fees consist of aggregate fees for assurance and related services related to the audit or review of our financial statements that are not reported under “Audit Fees” above.

(3) Tax fees consist of aggregate fees for professional services for tax compliance, tax advice and tax planning, primarily, fees related to tax preparation services.

(4) Other fees consists of amounts billed for services other than those noted above.

Our audit committee has adopted a policy and procedures for the pre-approval of audit and, if applicable, non-audit services rendered by our independent registered public accounting firm.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		FTS INTERNATIONAL, INC.

		/s/ Michael J. Doss
		Michael J. Doss
	March 9, 2018	Chief Executive Officer

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Michael J. Doss and Jennifer L. Keefe, and each of them, with the full power to act without the other, such person’s true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign, execute and file this Annual Report on Form 10-K and any or all amendments thereto, with all exhibits and schedules thereto, and other documents in connection therewith with the Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their substitute or substitutes, may lawfully do or cause to be done.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Michael J. Doss	Chief Executive Officer and Director	March 9, 2018
Michael J. Doss	(Principal Executive Officer)

/s/ Lance D. Turner	Chief Financial Officer and Treasurer	March 9, 2018
Lance D. Turner	(Principal Financial Officer and
	Principal Accounting Officer)

/s/ Goh Yong Siang	Chairman	March 9, 2018
Goh Yong Siang

/s/ Domenic J. Dell’Osso, Jr.	Director	March 9, 2018
Domenic J. Dell’Osso, Jr.

/s/ Bryan J. Lemmerman	Director	March 9, 2018
Bryan J. Lemmerman

/s/ Ong Tiong Sin	Director	March 9, 2018
Ong Tiong Sin

/s/ Boon Sim	Director	March 9, 2018
Boon Sim

/s/ Carol J. Johnson	Director	March 9, 2018
Carol J. Johnson

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FTS INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
(In millions, except per share amounts)	2017			2016			2015

Revenue
Revenue	$	1,352.7		$	529.5		$	1,331.8
Revenue from related parties	113.4			2.7			43.5
Total revenue	1,466.1			532.2			1,375.3

Operating expenses
Costs of revenue (excluding depreciation of $75.6, $98.9, and $152.3, respectively, included in depreciation and amortization below)	1,009.8			510.5			1,257.9
Selling, general and administrative	81.0			64.4			154.7
Depreciation and amortization	86.6			112.6			272.4
Impairments and other charges	1.8			12.3			619.9
(Gain) loss on disposal of assets, net	(1.4		)	1.0			5.9
Gain on insurance recoveries	(2.9		)	(15.1		)	—
Total operating expenses	1,174.9			685.7			2,310.8

Operating income (loss)	291.2			(153.5		)	(935.5		)

Interest expense, net	(86.7		)	(87.5		)	(77.2		)
(Loss) gain on extinguishment of debt, net	(1.4		)	53.7			(0.6		)
Equity in net loss of joint venture affiliate	(0.8		)	(2.8		)	(1.4		)

Income (loss) before income taxes	202.3			(190.1		)	(1,014.7		)
Income tax expense (benefit)	1.6			(1.6		)	(1.5		)

Net income (loss)	$	200.7		$	(188.5	)	$	(1,013.2	)

Net loss attributable to common stockholders	$	(25.9	)	$	(370.1	)	$	(1,158.1	)

Basic and diluted earnings (loss) per share attributable to common stockholders	$	(0.50	)	$	(7.14	)	$	(22.36	)
Shares used in computing basic and diluted earnings (loss) per share	51.8			51.8			51.8

The accompanying notes are an integral part of these consolidated financial statements.

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FTS INTERNATIONAL, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
(In millions, except share amounts)	2017			2016

ASSETS
Current assets
Cash	$	208.1		$	160.3
Accounts receivable, net	231.1			76.5
Accounts receivable from related parties	3.0			0.1
Inventories	44.5			24.8
Prepaid expenses and other current assets	19.9			17.7
Total current assets	506.6			279.4

Property, plant, and equipment, net	270.9			284.3
Intangible assets, net	29.5			29.5
Investment in joint venture affiliate	21.0			21.6
Other assets	3.0			2.0
Total assets	$	831.0		$	616.8

LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities
Accounts payable	$	138.3		$	60.8
Accrued expenses and other current liabilities	44.4			34.8
Total current liabilities	182.7			95.6

Long-term debt	1,116.4			1,188.7
Other liabilities	0.4			1.7
Total liabilities	1,299.5			1,286.0

Commitments and contingencies (Note 13)
Series A convertible preferred stock, $0.01 par value, 350,000 shares authorized, issued and outstanding at December 31, 2017 and 2016, respectively (aggregate amount of liquidation preference of $1,132.7 million at December 31, 2017);	349.8			349.8

Stockholders’ deficit
Common stock, $0.01 par value, 320,000,000 shares authorized, 51,782,735 and 51,783,762 shares issued and outstanding at December 31, 2017 and 2016 (Note 17)	35.9			35.9
Additional paid-in capital	3,712.1			3,712.1
Accumulated deficit	(4,566.3		)	(4,767.0		)
Total stockholders’ deficit	(818.3		)	(1,019.0		)
Total liabilities and stockholders’ deficit	$	831.0		$	616.8

The accompanying notes are an integral part of these consolidated financial statements.

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FTS INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
(In millions)	2017			2016			2015

Cash flows from operating activities
Net income (loss)	$	200.7		$	(188.5	)	$	(1,013.2	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	86.6			112.6			272.4
Amortization of debt discounts and issuance costs	3.9			3.8			3.2
Impairment of assets and goodwill	—			7.0			572.9
(Gain) loss on disposal of assets, net	(1.4		)	1.0			5.9
Loss (gain) on extinguishment of debt, net	1.4			(53.7		)	0.6
Gain on insurance recoveries	(2.9		)	(15.1		)	—
Inventory write-down	—			—			24.5
Acquisition earn-out adjustments	—			—			(3.4		)
Other non-cash items	0.5			2.0			3.8
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable	(154.9		)	24.0			373.2
Accounts receivable from related parties	(2.9		)	3.4			33.5
Inventories	(20.1		)	5.3			37.9
Prepaid expenses and other assets	(4.4		)	2.6			2.0
Accounts payable	65.2			2.8			(210.4		)
Accrued expenses and other liabilities	8.3			(17.0		)	(52.3		)
Net cash provided by (used in) operating activities	180.0			(109.8		)	50.6

Cash flows from investing activities
Capital expenditures	(64.0		)	(10.3		)	(79.1		)
Cash paid for acquisitions	—			—			(1.7		)
Investment in joint venture affiliate	—			—			(14.8		)
Proceeds from disposal of assets	4.1			31.5			9.7
Proceeds from insurance recoveries	4.2			19.0			—
Net change in restricted cash	0.1			2.9			(12.0		)
Other	1.0			—			—
Net cash (used in) provided by investing activities	(54.6		)	43.1			(97.9		)

Cash flows from financing activities
Proceeds from issuance of long-term debt	—			—			366.5
Payments of debt issuance costs	—			—			(6.0		)
Repayments of long-term debt	(77.6		)	(37.6		)	(58.9		)
Other	—			—			(0.2		)
Net cash (used in) provided by financing activities	(77.6		)	(37.6		)	301.4

Net increase (decrease) in cash and cash equivalents	47.8			(104.3		)	254.1
Cash and cash equivalents, beginning of period	160.3			264.6			10.5
Cash and cash equivalents, end of period	$	208.1		$	160.3		$	264.6

Supplemental cash flow information
Interest paid	$	83.2		$	84.2		$	74.3
Income tax payments, net	$	—		$	—		$	2.0
Supplemental disclosure of noncash investing activities
Capital expenditures included in accounts payable	$	13.6		$	1.2		$	1.4

The accompanying notes are an integral part of these consolidated financial statements.

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FTS INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

(Dollars in millions and	Common Stock				Additional Paid-in		Accumulated			Total Stockholders’
shares in thousands)	Shares		Amount		Capital		Deficit			Equity (Deficit)

Balance at January 1, 2015	51,843		$	35.9	$	3,710.4	$	(3,565.3	)	$	181.0

Net loss	—		—		—		(1,013.2		)	(1,013.2		)
Activity related to stock plans	(59	)	—		1.7		—			1.7
Balance at December 31, 2015	51,784		35.9		3,712.1		(4,578.5		)	(830.5		)

Net loss	—		—		—		(188.5		)	(188.5		)
Activity related to stock plans	(1	)	—		—		—			—
Balance at December 31, 2016	51,783		$	35.9	$	3,712.1	$	(4,767.0	)	$	(1,019.0	)

Net income	—		—		—		200.7			200.7
Balance at December 31, 2017	51,783		$	35.9	$	3,712.1	$	(4,566.3	)	$	(818.3	)

The accompanying notes are an integral part of these consolidated financial statements.

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FTS INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — DESCRIPTION OF BUSINESS

Throughout the notes to these consolidated financial statements, the terms “FTSI,” “we,” “us,” “our” or “ours” refer to FTS International, Inc., together with its consolidated subsidiaries.

We are one of the largest providers of hydraulic fracturing services in North America. Our services enhance hydrocarbon flow from oil and natural gas wells drilled by exploration and production (“E&P”), companies in shale and other unconventional resource formations. Our customers include Chesapeake Energy Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources, Inc., Diamondback Energy, Inc., EQT Company, Range Resources Corporation, and other leading E&P companies that specialize in unconventional oil and natural gas resources in North America. We are one of the top three hydraulic fracturing providers across our operating footprint, which consists of five of the most active major unconventional basins in the United States: the Permian Basin, the SCOOP/STACK Formation, the Marcellus/Utica Shale, the Eagle Ford Shale and the Haynesville Shale. Substantially all of our business activities support our well completion services. We manage our business, allocate resources, and assess our financial performance on a consolidated basis; therefore we do not have separate operating segments.

In 2014, we entered into a 15-year joint venture agreement with the Sinopec Group (“Sinopec”). This joint venture collaboration offers hydraulic stimulation services in China. The joint venture company, SinoFTS Petroleum Services Ltd. (“SinoFTS”), is owned 55% by Sinopec and 45% by us. SinoFTS will serve both Sinopec and other exploration and production companies throughout China. SinoFTS began performing hydraulic fracturing services in China in 2016.

Recent Developments: In February 2018 the Company completed an initial public offering of its common stock and completed a number of other transactions. See Note 17 — “Subsequent Events” for more information.

Concentrations of Risk

Our business activities are concentrated in the well completion services segment of the oilfield services industry in the United States. The market for these services is cyclical, and we depend on the willingness of our customers to make operating and capital expenditures to explore for, develop, and produce oil and natural gas in the United States. The willingness of our customers to undertake these activities depends largely upon prevailing industry conditions that are predominantly influenced by current and expected prices for oil and natural gas. Historically, a low commodity-price environment has caused our customers to significantly reduce their hydraulic fracturing activities and the prices they are willing to pay for those services. During these periods, these customer actions materially adversely affected our business, financial condition and results of operations.

Our customer base has historically been concentrated. Our business, financial condition and results of operations could be materially adversely affected if one or more of our significant customers ceases to engage us for our services on favorable terms, or at all, or fails to pay, or delays in paying, us significant amounts of our outstanding receivables. The following table shows the customers who represented more than 10% of our total revenue in any one of the periods indicated below:

	Year Ended December 31,
	2017	2016		2015

Newfield Exploration	*	18	%	*
EQT Production Company	*	12	%	12	%
EP Energy Corporation	*	11	%	*
Vine Oil and Gas, L.P.	*	10	%	*
Murphy Oil Corporation	*	*		11	%
Range Resources Corporation	*	*		13	%

* Less than 10%

Related Parties

We have historically provided services and sold equipment to Chesapeake Energy Corporation and its affiliates (“Chesapeake”), which beneficially owned approximately 30% of our outstanding common stock and had the right to designate two individuals to serve on our board of directors during the periods presented. Revenue earned from Chesapeake was $113.1 million, $2.4 million and $32.1 million in 2017, 2016 and 2015, respectively. All revenue earned from Chesapeake is based on the prevailing

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in the event of an “ownership change” under Section 382 of the Internal Revenue Code. We will adjust a previously established valuation allowance if we change our assessment of the amount of deferred income tax asset that is more likely than not to be realized.

Revenue Recognition

We recognize revenue when we have the right to invoice a customer under our contracts, which is generally upon the completion of a fracturing stage. We typically complete one or more stages per day. A stage is considered complete when we have met the specifications set forth by the customer, at which time the customer is obligated to pay us for the services rendered. The price for our services is agreed to with our customer for each stage completed. The price for our services typically includes an equipment charge and product charges for proppant, chemicals and other products actually consumed during the course of providing our services. The amount invoiced to our customer for a completed stage is not dependent upon the completion of any other stages.

In certain customer arrangements, we are guaranteed a minimum monthly amount of compensation in exchange for us providing exclusive use of a fracturing fleet to the customer. Under these arrangements, the amount invoiced to our customer for services performed is not dependent upon any future event.

Unconditional Purchase Obligations

We have historically entered into supply arrangements with our vendors, primarily for sand, that contain unconditional purchase obligations. These represent obligations to transfer funds in the future for fixed or minimum quantities of goods or services at fixed or minimum prices, such as “take-or-pay” contracts. We enter into these unconditional purchase obligation arrangements in the normal course of business to ensure that adequate levels of sourced product are available to us. To account for these arrangements, we must monitor whether we may be required to make a minimum payment to a vendor in a future period because our projected inventory purchases may not satisfy our minimum commitments. If we conclude that it is probable that we will make a minimum payment under these arrangements, we will record an estimated loss for these commitments in the current period.

Stock-Based Compensation

We measure all employee stock-based compensation awards using a fair value method and record this cost in the consolidated financial statements. Our stock-based compensation relates to restricted stock awards or restricted stock units issued to our employees. On the date that an equity-classified award is granted, we determine the fair value of the award and recognize the compensation cost over the requisite service period, which typically is the period over which the award vests. For liability-classified awards, we determine the fair value of the award at each reporting date and recognize a portion of the fair value equal to the amount of time that has passed in the requisite service period. For stock-based awards with graded vesting based solely on the satisfaction of a service condition, we recognize compensation cost as a single award on a straight-line basis. We account for forfeited awards as forfeitures occur, which results in a reversal of stock-based compensation cost previously recognized up to the date of the forfeiture. For stock-based awards with performance conditions that affect vesting, we only recognize compensation cost when it is probable that the performance conditions will be met.

Fair Value Measurements

Fair value is defined as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at a measurement date. We apply the following fair value hierarchy, which prioritizes the inputs used to measure fair value into three levels and bases the categorization within the hierarchy upon the lowest level of input that is available and significant to the fair value measurement:

· Level One: The use of quoted prices in active markets for identical financial instruments.

· Level Two: The use of quoted prices for similar instruments in active markets or quoted prices for identical or similar instruments in markets that are not active or other inputs that are observable in the market or can be corroborated by observable market data.

· Level Three: The use of significantly unobservable inputs that typically require the use of management’s estimates of assumptions that market participants would use in pricing.

New Accounting Standards Updates

In May 2014, the Financial Accounting Standards Board (“FASB”), issued Accounting Standards Update (“ASU”), 2014-09, Revenue from Contracts with Customers. The FASB has subsequently issued a number of additional ASUs to update this guidance. This guidance will supersede substantially all existing accounting guidance related to the accounting for revenue transactions. This

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guidance establishes a core principle that an entity should record revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. We have substantially completed the process of determining the effects that the new standard will have on our consolidated financial statements. Our approach included performing a review of key contracts and comparing historical accounting policies and practices to the new accounting guidance. Based on our assessment, we expect the adoption of this ASU to have an immaterial effect on our current revenue recognition process. We will reflect this standard in our consolidated financial statements beginning on January 1, 2018, utilizing the modified retrospective method. We do not expect to record a cumulative effect of accounting change upon adoption.

In February 2016, the FASB issued ASU 2016-02, Leases. This standard was issued to increase transparency and comparability among organizations by requiring that most leases be included on the balance sheet and by expanding disclosure requirements. This standard is scheduled to be effective for our financial statements beginning on January 1, 2019. We are in the process of determining the effects that the new standard will have on our consolidated financial statements. Our approach includes a review of existing leases and other executory contracts that may contain embedded leases and identifying the key terms that will be necessary for us to calculate the right-of-use asset and corresponding lease liability. Based upon our expected future lease payments on existing leases that are longer than twelve months, we expect that the adoption of this standard will have a material effect on our total assets and total liabilities; however, we have not yet completed the quantification of the amount of the change.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This standard was issued to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This standard is scheduled to be effective for our financial statements beginning on January 1, 2018. We adopted this standard on January 1, 2018, and expect it to have no effect on our statements of cash flows.

In November 2016, the FASB issued ASU 2016-18, Restricted Cash. This standard was issued to change the presentation of amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This standard is scheduled to be effective for our financial statements beginning on January 1, 2018, and we adopted the standard on that date. Restricted cash is classified as prepaid expenses and other current assets on our consolidated balance sheets and totaled $9.1 million at both December 31, 2017 and 2016. These amounts represent cash used to secure certain letters of credit. In February 2018, we closed on a new revolving credit facility, and issued replacement letters of credit under the new facility, which allowed us to cancel the cash secured letters of credit.

NOTE 3 — SUPPLEMENTAL BALANCE SHEET INFORMATION

Accounts Receivable

The following table summarizes our accounts receivable balance:

	December 31,
(In millions)	2017			2016
Trade accounts receivable	$	233.2		$	78.8
Allowance for doubtful accounts	(2.1		)	(2.3		)
Accounts receivable, net	$	231.1		$	76.5

The change in allowance for doubtful accounts is as follows:

(In millions)	2017			2016			2015
Balance at beginning of year	$	2.3		$	1.7		$	2.4
Provision for bad debts, net included in selling, general, and administrative expense	0.3			1.3			0.7
Uncollectible receivables written off	(0.5		)	(0.7		)	(1.4		)
Balance at end of year	$	2.1		$	2.3		$	1.7

Inventories

The following table summarizes our inventories:

	December 31,
(In millions)	2017		2016
Maintenance parts	$	34.5	$	18.1
Proppants and chemicals	7.5		5.0
Other	2.5		1.7
Total inventories	$	44.5	$	24.8

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Prepaid Expenses and Other Current Assets

The following table summarizes our prepaid expenses and other current assets:

	December 31,
(In millions)	2017		2016
Restricted cash	$	9.1	$	9.1
Prepaid expenses	7.1		6.2
Other	3.7		2.4
Total prepaid expenses and other current assets	$	19.9	$	17.7

Property, Plant, and Equipment, net

The following table summarizes our property, plant, and equipment:

							Estimated
	December 31,						Useful Life
(Dollars in millions)	2017			2016			(in years)
Service equipment	$	745.1		$	763.4		2.5 – 10
Buildings and improvements	63.1			63.5			15 – 39
Office, software, and other equipment	43.7			45.2			3 – 7
Vehicles and transportation equipment	4.4			5.5			5 – 20
Land	7.7			8.0			N/A
Construction-in-process and other	35.3			18.6			N/A
Total property, plant, and equipment	899.3			904.2
Accumulated depreciation and amortization	(628.4		)	(619.9		)
Total property, plant, and equipment, net	$	270.9		$	284.3

Depreciation expense was $86.6 million, $112.6 million and $169.9 million in 2017, 2016 and 2015, respectively.

Accrued Expenses and Other Current Liabilities

The following table summarizes our accrued liabilities:

	December 31,
(In millions)	2017		2016
Sales, use, and property taxes	$	19.3	$	17.7
Employee compensation and benefits	13.6		5.6
Interest	5.7		6.0
Insurance	3.3		4.2
Other	2.5		1.3
Total accrued expenses and other current liabilities	$	44.4	$	34.8

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NOTE 4 — GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

The changes in the carrying amount of goodwill were as follows for the year ended December 31, 2015. There was no activity during 2016 or 2017.

(In millions)	Goodwill		Accumulated Impairment Losses			Net

Balance at January 1, 2015	$	7.1	$	—		$	7.1
Goodwill impairment	—		(7.1		)	(7.1		)
Balance at December 31, 2015	$	7.1	$	(7.1	)	$	—

In connection with our 2014 wireline acquisition, we agreed to pay up to $12.5 million of contingent cash consideration in each of 2015 and 2016 based on the achievement of earnings targets. The final fair value of this contingent consideration at the acquisition date was $3.4 million. We were required to measure the fair value of the contingent consideration at each reporting date. The fair value of the contingent consideration was zero at both December 31, 2015 and 2016. The decrease in the fair value of the contingent consideration was due to reduced actual and forecasted cash flows for this reporting unit during the earn-out periods. These fair values were based on the use of unobservable inputs and are classified as Level 3 in the FASB’s fair value hierarchy.

The reduced actual and forecasted cash flows at June 30, 2015, were an indicator that we should conduct an interim goodwill impairment test for our wireline reporting unit in the second quarter of 2015. As a result of this test, we recorded a non-cash impairment of $7.1 million in the second quarter of 2015. We estimated the fair value using the income approach. The significant inputs employed in determining fair value included, but were not limited to, projected financial information, growth rates, terminal value, and discount rates. This fair value was based on the use of unobservable inputs and is classified as Level 3 in the FASB’s fair value hierarchy.

Other Intangible Assets

The following table summarizes our other intangible assets and accumulated amortization:

(In millions)	Gross Carrying Value		Accumulated Amortization			Impairments			Net
At December 31, 2017
Tradename	59.7		—			(30.2		)	29.5

At December 31, 2016
Tradename	59.7		—			(30.2		)	29.5

At December 31, 2015
Customer relationships	$	873.8	$	(403.3	)	$	(470.5	)	$	—
Tradename	59.7		—			(30.2		)	29.5
Proprietary chemical blends	73.5		(68.5		)	(5.0		)	—
Total	$	1,007.0	$	(471.8	)	$	(505.7	)	$	29.5

Our tradename has an indefinite life and, therefore, is not amortized. For our definite-lived intangible assets, the weighted-average amortization periods prior to the impairments in 2015 were ten years for customer relationships and five years for proprietary chemical blends. In the fourth quarter of 2015 we impaired all of our customer relationships and proprietary chemical blends. See Note 9 — “Impairments and Other Charges” for more discussion of our 2015 impairments.

Amortization for definite-lived intangible assets was $102.5 million in 2015. Estimated amortization expense, excluding any future acquisitions, for each of the next five years is zero due to the impairments recorded in 2015.

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NOTE 5 — DEBT

The following table summarizes our long-term debt:

	December 31,
(In millions)	2017			2016
Senior floating rate notes due June 2020	$	290.0		$	350.0
Term loan due April 2021	431.0			431.0
Senior notes due May 2022	409.0			426.3
Total principal amount	1,130.0			1,207.3
Less unamortized discount and debt issuance costs	(13.6		)	(18.6		)
Total long-term debt	$	1,116.4		$	1,188.7
Estimated fair value of long term debt	$	1,113.8		$	1,060.7

Estimated fair values for our term loan and senior notes were determined using recent trading activity and/or bid-ask spreads and are classified as Level 2 in the FASB’s fair value hierarchy.

2020 Senior Floating Rate Notes

On June 1, 2015, we completed an offering of $350 million of senior secured floating rate notes due June 15, 2020, in a private offering to qualified institutional buyers (“2020 Senior Notes”). The 2020 Senior Notes bear interest at a three-month London Interbank Offered Rate (“LIBOR”) plus a margin of 7.5% per annum. Interest is payable quarterly, in arrears, on March 15, June 15, September 15 and December 15.

The 2020 Senior Notes were issued at a discount of $3.5 million for aggregate consideration of $346.5 million and resulted in net proceeds to the Company of $340.5 million after debt issuance costs of $6.0 million.

The obligation to pay principal and interest on the 2020 Senior Notes is jointly and severally guaranteed on a full and unconditional basis by all of our wholly owned domestic subsidiaries. The 2020 Senior Notes are secured on a first priority basis by our accounts receivable, inventory, deposit accounts, and certain hydraulic fracturing and other equipment. The 2020 Senior Notes are secured on a second priority basis by 100% of the equity interests of our existing and future domestic subsidiaries and 65% of the voting equity interests of our existing and future foreign subsidiaries.

The 2020 Senior Notes are redeemable, at our option, beginning on June 15, 2016, at a premium of 3%. The redemption premium then declines each year until June 15, 2018, at which time we may redeem the notes at par value.

The 2020 Senior Notes contain covenants that could, in certain circumstances, limit our ability to issue additional debt, repurchase or pay dividends on our common or preferred stock, sell substantially all of our assets, make certain investments, or enter into certain other transactions.

In 2017, we repaid $60.0 million of aggregate principal amount of 2020 Senior Notes. We recognized a loss on debt extinguishment of $1.8 million.

We were in compliance with all of the covenants in the indenture governing our 2020 Senior Notes at December 31, 2017 and 2016.

On February 22, 2018, we repaid the remaining principal amount of the 2020 Senior Notes. See Note 17 — “Subsequent Events” for more information.

2022 Senior Notes

On April 16, 2014, we completed an offering of $500 million of 6.25% senior secured notes due May 1, 2022, in a private offering to qualified institutional buyers (“2022 Senior Notes”). Interest is payable semiannually, in arrears, on May 1 and November 1. The Company received net proceeds of $489.7 million after debt issuance costs of $10.3 million.

The obligation to pay principal and interest on the 2022 Senior Notes is jointly and severally guaranteed on a full and unconditional basis by all of our wholly owned domestic subsidiaries. The 2022 Senior Notes are secured on a first priority basis by 100% of the equity interests of our existing and future domestic subsidiaries and 65% of the voting equity interests of our existing and

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future foreign subsidiaries. The 2022 Senior Notes are secured on a second priority basis by our accounts receivable, inventory, and deposit accounts, which also secure our 2020 Senior Notes as discussed above. All security requirements for the 2022 Senior Notes will cease upon the full repayment of our $550 million term loan discussed below.

The 2022 Senior Notes are redeemable, at our option, beginning on May 1, 2017, at a premium of approximately 4.7%. The redemption premium then declines each year until May 1, 2020, at which time we may redeem the notes at par value.

The 2022 Senior Notes contain covenants that could, in certain circumstances, limit our ability to issue additional debt, repurchase or pay dividends on our common or preferred stock, sell substantially all of our assets, make certain investments, or enter into certain other transactions.

In 2017, we repurchased $17.3 million of aggregate principal amount of 2022 Senior Notes in the qualified institutional market. We recognized a gain on debt extinguishment of $0.4 million. In 2016, we repurchased $43.7 million of aggregate principal amount of 2022 Senior Notes in the qualified institutional market. We recognized a gain on debt extinguishment of $25.4 million.

We were in compliance with all of the covenants in the indenture governing our 2022 Senior Notes at December 31, 2017 and 2016.

Term Loan

On April 16, 2014, we entered into a $550 million term loan, which matures on April 16, 2021, (“Term Loan”) with a group of lenders with Wells Fargo Bank, N.A., as administrative agent. The Term Loan bears interest at LIBOR plus a margin of 4.75% per annum, with a 1.00% LIBOR floor. Interest is payable on interest rate reset dates, which generally will be on a three-month basis.

The Term Loan was issued at a discount of $2.7 million for aggregate consideration of $547.3 million and resulted in net proceeds to the Company of $540.0 million after debt issuance costs of $7.3 million.

The obligation to pay principal and interest on the Term Loan is jointly and severally guaranteed on a full and unconditional basis by all of our wholly owned domestic subsidiaries. The Term Loan is secured on the same basis as the 2022 Senior Notes as discussed above.

The Term Loan contains substantially the same covenants as the 2022 Senior Notes and the 2020 Senior Notes. None of the Term Loan, the 2022 Senior Notes, or the 2020 Senior Notes contain maintenance financial covenants.

In 2016, we repaid $49.0 million of aggregate principal amount of Term Loan. We recognized a gain on debt extinguishment of $28.3 million.

We were in compliance with all of the covenants in the Term Loan at December 31, 2017 and 2016.

Revolving Credit Facility

On April 16, 2014, we entered into a five-year, $200 million revolving credit facility with a group of lenders and Wells Fargo Bank, N.A., as administrative agent. In connection with the issuance of the 2020 Senior Notes, we repaid all amounts outstanding under, and terminated, this revolving credit facility in 2015. We incurred a loss of $1.7 million, which primarily related to the write-off of deferred issuance costs, in connection with the termination of the revolving credit facility. This amount is classified as “Gain or loss on extinguishment of debt, net” on our Consolidated Statements of Operations.

The following table summarizes the maturities of our long-term debt at December 31, 2017:

(In millions)
2018	$	—
2019	—
2020	290.0
2021	431.0
2022	409.0
2023 and thereafter	—
Total principal amount of long-term debt	$	1,130.0

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	Number of Units (1) (In thousands)		Weighted- Average Grant Date Fair Value (1)
Unvested balance at January 1, 2015	60		$	42.25
Granted	—		—
Vested or released (2)	(57	)	41.56
Forfeited	(3	)	51.94
Unvested balance at December 31, 2015	—		$	—

(1) The number of units and the fair value per share presented in this table have been adjusted to give effect to a 69.258777 : 1 reverse stock split that occurred in February 2018 in connection with the completion of an initial public offering of our common stock. See Note 17 — “Subsequent Events” for more information.

(2) Certain granted but unvested shares are released for tax withholdings on the participant’s behalf.

The total fair value of restricted stock vested in 2015 was $2.4 million. At December 31, 2017 and 2016, there were no unvested restricted stock awards.

Restricted Stock Units

In 2014, our stockholders approved the 2014 Long-Term Incentive Plan (“2014 LTIP”). The 2014 LTIP authorized the grant of up to 55 million restricted stock units (“RSU”) to salaried employees of the Company, as determined by the compensation committee of the board of directors. This plan originally was set to expire on March 3, 2024. The 2014 LTIP allowed for the grant of stock-settled and cash-settled RSUs. The Company had the power to elect, at its sole discretion, to settle any or all of the stock-settled RSUs wholly or partly in cash.

The awards that were granted in 2014 had three vesting conditions: a performance condition based on Company goals, a performance condition based on the occurrence of a qualifying liquidity event such as an initial public offering of our common stock, and a service-period condition. The performance condition was based on Company goals that provided for an upward or downward adjustment to the RSUs granted based on Company performance. The service-period condition provided that 50% of the number of adjusted RSUs vested on each of December 31, 2015, and December 31, 2016.

The following table summarizes the 2017 transactions related to the stock-settled RSUs:

	Number of Units (1) (In thousands)		Weighted- Average Grant Date Fair Value (1)
Unvested balance at January 1, 2017	159		$	15.24
Granted	—		—
Vested	—		—
Forfeited	(42	)	15.24
Unvested balance at December 31, 2017	117		$	15.24

Under generally accepted accounting principles for stock-based compensation, a performance condition that affects vesting and is based on a corporate liquidity event such as an initial public offering of common stock precludes the recognition of compensation expense related to the awards until this performance condition has been met. Therefore, no compensation expense for these awards will be recognized until this performance condition has been met. At December 31, 2017, there was $1.8 million of total unrecognized compensation cost related to unvested stock-settled RSUs.

The compensation cost charged against income for all stock-based compensation was zero, zero and $1.8 million in 2017, 2016 and 2015, respectively. The total income tax benefit for all stock-based compensation was $0.2 million in 2015; however, such benefit was offset by the valuation allowance against our deferred tax assets.

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In February 2018, we completed an initial public offering of our common stock. See Note — 17 “Subsequent Events” for more information. This transaction qualified as the final vesting condition for these RSUs. The Company elected to settle all RSUs on a cash basis. The compensation expense recognized in 2018 for the stock-settled RSUs was $2.0 million. The compensation expense recognized in 2018 for the cash-settled RSUs was $1.7 million. The 2014 LTIP was terminated after the payout of the RSUs.

NOTE 8 — RETIREMENT PLAN

We offer a 401(k) defined contribution retirement plan (“401(k) Plan”), which allows a participant to defer, by payroll deductions, from 0% to 100% of the participant’s annual compensation, limited to certain annual maximums set by the Internal Revenue Code. The 401(k) Plan has historically provided a discretionary matching contribution to each participant’s account. Company matching contributions to the 401(k) Plan are made in cash and were $1.5 million, zero, and $5.5 million in 2017, 2016 and 2015, respectively. The Company suspended matching contributions in July 2015 and resumed making contributions in July 2017.

NOTE 9 — IMPAIRMENTS AND OTHER CHARGES

The following table summarizes our impairments and other charges:

	Year Ended December 31,
(In millions)	2017		2016		2015
Impairment of assets and goodwill	$	—	$	7.0	$	572.9
Supply commitment charges	1.2		2.5		11.0
Lease abandonment charges	0.6		2.0		1.8
Employee severance costs	—		0.8		13.1
Inventory write-down	—		—		24.5
Acquisition earn-out adjustments	—		—		(3.4		)
Total impairments and other charges	$	1.8	$	12.3	$	619.9

Impairment of Assets and Goodwill

During 2016, we recorded asset impairments of $7.0 million related to service equipment and real property that we no longer use and identified to sell. During the first nine months of 2015, we recorded a non-cash goodwill impairment of $7.1 million for our wireline reporting unit and an asset impairment of $0.5 million related to real property that we no longer use.

In the fourth quarter of 2015, we concluded that the persistent low commodity price environment and its effect on our current and forecasted cash flows required us to perform multiple asset impairment tests. As a result, we recorded a number of asset impairments in the fourth quarter of 2015.

· We evaluated the long-lived assets of our pressure pumping asset group for impairment and concluded that the fair value of this asset group was lower than the carrying value of the assets in the asset group. We recognized a total impairment for this asset group of $487.0 million. Of this amount, $461.4 million was attributable to our customer relationships, $20.6 million was attributable to certain equipment, and $5.0 million was attributable to our proprietary chemical blends.

· We evaluated the long-lived assets of our wireline asset group for impairment and concluded that the fair value of this asset group was lower than the carrying value of the assets in the asset group. We recognized a total impairment for this asset group of $33.3 million. Of this amount $24.2 million was attributable to certain equipment and $9.1 million was attributable to our customer relationships.

· We evaluated our tradename intangible asset for impairment and concluded that the fair value of this asset was lower than its carrying value, which resulted in an impairment of $30.2 million.

· We recorded $14.8 million of impairments for certain land and buildings that we no longer use.

See Note 14 — “Nonrecurring Fair Value Measurements” for more information on these impairments.

Supply Commitment Charges

We have recorded supply commitment charges related to contractual inventory purchase commitments to certain proppant suppliers. In 2017, 2016 and 2015, we recorded charges under these supply arrangements of $1.2 million, $2.5 million and $11.0 million, respectively. These charges were attributable to our decreased volume of purchases from these suppliers due to our lower activity levels and/or certain customers procuring their own proppants.

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NOTE 12 — INCOME TAXES

The following table summarizes the components of income tax expense (benefit):

	Year Ended December 31,
(In millions)	2017		2016			2015
Current:
Federal	$	—	$	—		$	—
State	1.6		(1.6		)	(1.5		)
Total current	1.6		(1.6		)	(1.5		)
Total deferred	—		—			—
Income tax expense (benefit)	$	1.6	$	(1.6	)	$	(1.5	)

Actual income tax expense (benefit) differed from the amount computed by applying the statutory federal income tax rate to income (loss) before income taxes as follows:

	Year Ended December 31,
(In millions)	2017			2016			2015
Income (loss) before income taxes	$	202.3		$	(190.1	)	$	(1,014.7	)
Statutory federal income tax rate	35.0		%	35.0		%	35.0		%
Federal income tax expense (benefit) at statutory rate	70.8			(66.5		)	(355.1		)
State income tax expense (benefit), net of federal effect	7.2			(6.7		)	(26.8		)
Effect of changes in income apportionment amongst states	8.2			—			—
Effect of U.S. tax law change	424.8			—			—
Other items, net	1.7			0.1			0.4
Change in valuation allowance	(511.1		)	71.5			380.0
Income tax expense (benefit)	$	1.6		$	(1.6	)	$	(1.5	)

Effective tax rate	0.8		%	0.8		%	0.1		%

In December 2017, the President of the United States signed into law the Tax Cuts and Jobs Act of 2017 that, among other things, reduced the federal income tax rate from 35% to 21% beginning on January 1, 2018. Under generally accepted accounting principles for income taxes, we are required to recognize the effects of changes in tax laws and tax rates on deferred tax assets and liabilities in the period in which the new legislation is enacted. Accordingly, we remeasured our federal deferred tax assets as of December 31, 2017, to a 21% rate. This would have resulted in additional tax expense of $424.8 million in 2017; however, this amount has been offset by a corresponding change in our valuation allowance. We are still in the process of evaluating the new foreign tax law provisions that are effective beginning January 2018.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below:

	December 31,
(In millions)	2017			2016
Deferred tax assets:
Goodwill and intangible assets	$	365.3		$	655.7
Federal net operating loss carryforwards	338.0			564.9
State net operating loss carryforwards, net of federal benefit	39.7			34.7
Accrued liabilities	4.5			7.9
Other	2.3			3.7
Gross deferred tax assets	749.8			1,266.9
Valuation allowance	(735.5		)	(1,246.6		)
Total deferred tax assets	14.3			20.3

Deferred tax liabilities:
Property, plant, and equipment	14.3			20.3
Total deferred tax liabilities	14.3			20.3

Net deferred tax assets	$	—		$	—

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Because of our valuation allowance, our net deferred tax assets are zero and no deferred tax assets or liabilities are included in the Consolidated Balance Sheets.

At December 31, 2017, our federal net operating loss carryforwards were $1.6 billion, which will expire on various dates between 2032 and 2036. At December 31, 2017, our state net operating loss carryforwards were approximately $618 million, which will expire on various dates between 2018 and 2037.

A reconciliation of the valuation allowance for deferred tax assets from January 1, 2015 to December 31, 2017 is as follows:

(In millions)	2017			2016		2015
Balance at January 1	$	1,246.6		$	1,175.1	$	795.1
Additions, charged to expense	—			71.5		380.0
Deductions	(511.1		)	—		—
Balance at December 31	$	735.5		$	1,246.6	$	1,175.1

In 2012, we established a full valuation allowance with respect to our U.S. federal net deferred tax assets and state net deferred tax assets. We have recorded a full valuation allowance for these net deferred tax assets for each year since 2012. Deferred tax assets related to our U.S. federal and state operating losses are still available to us to offset future taxable income, subject to limitations in the event of a change of control under Section 382 of the Internal Revenue Code. At December 31, 2017, we had not incurred such an ownership change.

At each reporting date, we consider all available positive and negative evidence to evaluate whether our deferred tax assets are more likely than not to be realized. A significant piece of negative evidence that we consider is cumulative losses (generally defined as losses before income taxes) incurred in recent years. Such evidence limits our ability to consider other subjective evidence such as our projections for future taxable income. We also concluded that this negative evidence was not overcome by considering other sources of taxable income, which included the reversal of taxable temporary differences and tax-planning strategies.

Since the second quarter of 2017, the Company has been generating taxable income which we will offset with net operating losses incurred in prior years. This represents positive evidence that we may be able to realize some or all of our deferred tax assets; however, we determined that this positive evidence does not yet outweigh the negative evidence of our losses incurred in recent years. For example, at December 31, 2017 and 2016, we had incurred cumulative losses over the most recent three-year periods. If we continue to generate taxable income in 2018, this will be additional positive evidence that we may be able to realize our net deferred tax assets. We will adjust the valuation allowance as we change our assessment of the amount of net deferred tax assets that are more likely than not to be realized; however, due to the negative evidence of our cumulative losses in recent years and the significant cyclicality of our business, we believe that the earliest period when we may adjust the valuation allowance is the fourth quarter of 2018.

A reconciliation of the liability for gross unrecognized income tax benefits (excluding interest) from January 1, 2015 to December 31, 2017 is as follows:

(In millions)	2017		2016			2015
Balance at January 1	$	—	$	1.4		$	2.5
Lapse in applicable statute of limitations	—		(1.4		)	(1.1		)
Balance at December 31	$	—	$	—		$	1.4

The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate was zero at December 31, 2017 and 2016, respectively.

We recognize accrued interest and penalties related to any uncertain tax positions as part of the tax provision. At December 31, 2017 and 2016, we had no accrued interest expense associated with unrecognized tax benefits. Interest expense associated with unrecognized tax benefits was $0.1 million in 2015.

FTS International, Inc. and its U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. We do not currently have significant operations or undistributed earnings in foreign jurisdictions. Our income tax returns are currently subject to examination in federal and state jurisdictions primarily for tax years from 2014 through 2016.

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NOTE 13 — COMMITMENTS AND CONTINGENCIES

Operating Leases

We lease certain administrative and sales offices, operational facilities and office equipment in various cities. We also lease some service equipment and light duty vehicles. Some of our lease agreements include renewal or purchase options that we may choose to exercise at the end of the lease term. Total rental expense under our operating leases was $19.6 million, $19.6 million and $31.7 million in 2017, 2016 and 2015, respectively.

At December 31, 2017, our future minimum rental commitments due under non-cancellable operating leases is summarized below

(In millions)	2018		2019		2020		2021		2022		Thereafter
Operating leases	$	14.3	$	12.7	$	8.7	$	5.5	$	1.5	$	1.4

Purchase Obligations

We have purchase commitments with certain vendors to supply a significant portion of the proppant used in our operations. These agreements have remaining terms ranging from one to seven years. Some of these agreements are take-or-pay agreements with minimum unconditional purchase obligations. These minimum purchase obligations could change based upon the vendors ability to supply a minimum requirement. We also have purchase commitments to a vendor to assist us with the delivery of proppant to our job locations. Total purchases made under these agreements were $46.0 million, $20.9 million and $49.7 million in 2017, 2016 and 2015, respectively. At December 31, 2017, our future minimum purchase commitments due under these agreements is summarized below:

(In millions)	2018		2019		2020		2021		2022		Thereafter
Purchase obligations	$	79.8	$	77.2	$	56.2	$	47.9	$	47.9	$	96.0

Litigation

In the ordinary course of business, we are subject to various legal proceedings and claims, some of which may not be covered by insurance. Many of these legal proceedings and claims are in early stages, and many of them seek an indeterminate amount of damages. We estimate and provide for potential losses that may arise out of legal proceedings and claims to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different from these estimates. When preparing our estimates, we consider, among other factors, the progress of each legal proceeding and claim, our experience and the experience of others in similar legal proceedings and claims, and the opinions and views of legal counsel.

In 2012, Continental Industries Group, Inc. (“Continental”) filed two lawsuits against FTS International, Inc. and FTS International Services, LLC in the United States District Court, Southern District of New York that were combined into one action entitled Continental Industries Group, Inc. v. FTS International, Inc. and FTS International Services, LLC. In its suit, Continental claimed that FTSI (a) wrongfully terminated a supply agreement entered into by the parties in 2011, and (b) wrongfully cancelled two alleged purchase orders for the procurement of guar gum, a key component of certain chemicals we utilize in performing our services for customers. Pursuant to the supply agreement, Continental had agreed to enter into a joint venture with a Company in India to arrange for the construction of a guar gum-processing factory that would produce a five year supply of guar for FTSI. FTSI terminated the supply agreement in mid-2012 before the factory was complete. With respect to the purchase order claim, FTSI had expressed interest in purchasing guar gum from Continental in transactions separate from the supply agreement. FTSI did not purchase the guar gum. Continental claimed that valid purchase orders had been formed and that FTSI wrongfully terminated the purchase orders when it decided not to purchase the guar gum. Continental sought damages of approximately $58.0 million related to the supply agreement claim and approximately $4.5 million related to the purchase order claim. FTSI filed counterclaims against Continental seeking damages in excess of $69.0 million representing the difference between the price it paid for guar gum in the spot market and the price it would have paid under the supply agreement. A jury trial for this case was held and, on November 3, 2015, the jury returned verdicts in favor of Continental for both claims. The jury awarded damages to Continental in the aggregate amount of $5.3 million, of which $2.1 million related to the supply agreement case and $3.2 million related to the purchase order case. In January 2016, we settled this lawsuit with Continental for a confidential amount and the financial effects of this matter have been included in our consolidated financial statements as of December 31, 2015.

We believe that costs associated with other legal matters will not have a material adverse effect on our consolidated financial statements.

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NOTE 14 — NONRECURRING FAIR VALUE MEASUREMENTS

The following table represents the placement in the fair value hierarchy of assets that were measured at fair value on a nonrecurring basis. See Note 9 — “Impairments and Other Charges” for further discussion.

	Previous		Total
	Carrying		Fair		Fair value measurements using
	Values (1)		Value (1)		Level 1		Level 2		Level 3
During 2016
Property no longer used	$	1.0	$	—	$	—	$	—	$	—
Long-lived assets held for sale (2)	12.4		6.4		—		—		6.4
	$	13.4	$	6.4	$	—	$	—	$	6.4
During 2015
Pressure pumping asset group (3)
Customer relationships (4)	$	461.4	$	—	$	—	$	—	$	—
Equipment (5)	424.0		403.4		—		—		403.4
Proprietary chemical blends (6)	5.0		—		—		—		—
	$	890.4	$	403.4	$	—	$	—	$	403.4
Wireline asset group (2)
Property and equipment (5) (6)	$	39.2	$	15.0	$	—	$	—	$	15.0
Customer relationships (4)	9.1		—		—		—		—
Goodwill	7.1		—		—		—		—
	$	55.4	$	15.0	$	—	$	—	$	15.0

Tradename (4)	$	59.7	$	29.5	$	—	$	—	$	29.5
Property no longer used (6)	$	22.8	$	7.5	$	—	$	—	$	7.5

(1) Represents the value on the date of the fair value measurement.

(2) Equipment value based on pending contract price. Assets held for sale are classified as “Prepaid expenses and other current assets” on our Consolidated Balance Sheets.

(3) Valued using the income approach and the market approach valuation techniques.

(4) Valued using the income approach.

(5) Equipment valued using the cost approach, which is a valuation technique that estimates the amount that would be currently required to replace an asset’s service capacity.

(6) Property valued using the market approach based on the sales prices of comparable properties and/or estimates obtained from commercial brokers.

NOTE 15 — EARNINGS (LOSS) PER SHARE

The numerators and denominators of the basic and diluted earnings (loss) per share (“EPS”) computations for our common stock are calculated as follows:

	Year Ended December 31,
(In millions, except per share amounts)	2017			2016			2015
Numerator:
Net income (loss)	$	200.7		$	(188.5	)	$	(1,013.2	)
Convertible preferred stock accretion	(226.6		)	(181.6		)	(144.9		)
Net loss attributable to common stockholders used for basic EPS computation	(25.9		)	(370.1		)	(1,158.1		)

Add back the effect of dilutive securities:
Convertible preferred stock accretion (2)	—			—			—
Net loss attributable to common stockholders used for diluted EPS computation	$	(25.9	)	$	(370.1	)	$	(1,158.1	)

Denominator:
Weighted average shares used for basic EPS computation (1)	51.8			51.8			51.8
Effect of dilutive securities:
Convertible preferred stock (2)	—			—			—
Restricted stock units (3)	—			—			—
Dilutive potential common shares	—			—			—
Number of shares used for diluted EPS computation	51.8			51.8			51.8

Basic and diluted EPS	$	(0.50	)	$	(7.14	)	$	(22.36	)

F-23

Table of Contents

(1) The weighted average shares outstanding has been adjusted to give effect to a 69.258777 : 1 reverse stock split that occurred in February 2018 in connection with the completion of an initial public offering of our common stock. See Note 17 — “Subsequent Events” for more information.

(2) Dilutive securities in our diluted EPS calculation do not include the effects of converting the convertible preferred stock because the effect would be antidilutive. The number of common stock equivalents attributable to convertible preferred stock was 13.0 million shares for all periods presented after giving effect to the reverse stock split discussed above.

(3) Dilutive securities in our diluted EPS calculation do not include RSUs granted under our 2014 LTIP. Vesting of these RSUs is dependent upon the satisfaction of both a service condition and a corporate liquidity event such as an initial public offering of our common stock. As of December 31, 2017, a corporate liquidity event had not occurred; therefore, the holders of these RSUs had no rights in our undistributed earnings. Therefore, they were excluded from the effect of dilutive securities. The number of common stock equivalents attributable to the RSUs were 117 thousand shares, 159 thousand shares and 238 thousand shares in 2017, 2016 and 2015, respectively, after giving effect to the reverse stock split discussed above.

NOTE 16 — SELECTED QUARTERLY DATA (UNAUDITED)

	Three Months Ended
(In millions, except per share amounts)	March 31, 2017			June 30, 2017			September 30, 2017			December 31, 2017

Revenue
Revenue	$	191.9		$	304.4		$	409.8		$	446.6
Revenue from related parties	21.6			40.5			39.2			12.1
Total revenue	213.5			344.9			449.0			458.7

Operating expenses
Costs of revenue	174.8			236.3			298.8			299.9
Selling, general and administrative	19.5			20.8			21.7			19.0
Depreciation and amortization	21.8			21.3			22.1			21.4
Impairments and other charges	0.1			1.2			0.1			0.4
(Gain) loss on disposal of assets, net	(0.4		)	(0.4		)	(0.8		)	0.2
Gain on insurance recoveries	(2.6		)	(0.3		)	—			—
Total operating expenses	213.2			278.9			341.9			340.9

Operating income	0.3			66.0			107.1			117.8

Interest expense, net	(21.2		)	(21.5		)	(22.1		)	(21.9		)
Loss on extinguishment of debt, net	—			—			—			(1.4		)
Equity in net income (loss) of joint venture affiliate	0.9			0.2			(1.0		)	(0.9		)

Income (loss) before income taxes	(20.0		)	44.7			84.0			93.6
Income tax expense	0.1			0.4			0.4			0.7

Net income (loss)	$	(20.1	)	$	44.3		$	83.6		$	92.9

Net income (loss) attributable to common stockholders	$	(71.4	)	$	(10.5	)	$	25.1		$	30.9

Basic and diluted earnings (loss) per share attributable to common stockholders	$	(1.38	)	$	(0.20	)	$	0.48		$	0.60
Shares used in computing basic and diluted earnings (loss) per share	51.8			51.8			51.8			51.8

F-24

Table of Contents

	Three Months Ended
(In millions, except per share amounts)	March 31, 2016			June 30, 2016			September 30, 2016			December 31, 2016

Revenue
Revenue	$	147.6		$	105.7		$	123.8		$	152.4
Revenue from related parties	1.1			—			1.6			—
Total revenue	148.7			105.7			125.4			152.4

Operating expenses
Costs of revenue	141.2			102.8			125.7			140.8
Selling, general and administrative	20.2			15.5			15.8			12.9
Depreciation and amortization	30.1			29.1			28.3			25.1
Impairments and other charges	1.6			3.9			5.2			1.6
(Gain) loss on disposal of assets, net	2.8			(1.7		)	—			(0.1		)
Gain on insurance recoveries	(12.5		)	(2.6		)	—			—
Total operating expenses	183.4			147.0			175.0			180.3

Operating loss	(34.7		)	(41.3		)	(49.6		)	(27.9		)

Interest expense, net	(22.3		)	(22.4		)	(21.4		)	(21.4		)
Loss on extinguishment of debt, net	—			1.4			52.3			—
Equity in net loss of joint venture affiliate	(1.0		)	(0.9		)	(0.7		)	(0.2		)

Loss before income taxes	(58.0		)	(63.2		)	(19.4		)	(49.5		)
Income tax benefit	—			—			—			(1.6		)

Net loss	$	(58.0	)	$	(63.2	)	$	(19.4	)	$	(47.9	)

Net loss attributable to common stockholders	$	(99.4	)	$	(107.0	)	$	(65.8	)	$	(97.9	)

Basic and diluted earnings (loss) per share attributable to common stockholders	$	(1.92	)	$	(2.07	)	$	(1.27	)	$	(1.89	)
Shares used in computing basic and diluted earnings (loss) per share	51.8			51.8			51.8			51.8

F-25

Market Price	High		Low
First Quarter (February 2, 2018 to March 7, 2018)	$	21.52	$	15.02

Exhibit Number		Description
3.1	***	Amended and Restated Certificate of Incorporation of the Company

3.2	***	Amended and Restated Bylaws of the Company

4.1	***	Indenture, dated as of April 16, 2014, among FTS International, Inc., as issuer, the guarantors named therein and U.S. Bank National Association, as collateral agent and trustee

4.2	***	Indenture, dated as of June 1, 2015, among FTS International, Inc., as issuer, the guarantors named therein and U.S. Bank National Association, as collateral agent and trustee

4.3	***	Registration Rights Agreement

4.4	***	Investors’ Rights Agreement by and among FTS International, Inc., Maju Investments (Mauritius) Pte Ltd and CHK Energy Holdings, Inc.

4.5	***	Investors’ Rights Agreement by and among FTS International, Inc., Senja Capital Ltd and Hampton Asset Holding Ltd.

10.1	***	Term Loan Agreement, dated as of April 16, 2014, among FTS International, Inc., Wells Fargo Bank, National Association, as administrative agent, and other lenders party thereto

10.2	***†	Employment Agreement, dated as of December 6, 2014, between FTS International, Inc. and Perry Harris

10.3	***†	Severance Agreement, dated as of May 3, 2016, between FTS International, Inc. and Michael J. Doss

10.4	***†	Severance Agreement, dated as of May 3, 2016, between FTS International, Inc. and Buddy Petersen

10.5	***†	Severance Agreement, dated as of May 3, 2016, between FTS International, Inc. and Lance Turner

10.6	***†	Letter Agreement, dated as of August 5, 2015, between FTS International, Inc. and Lance Turner

10.7	***†	Letter Agreement, dated as of March 29, 2017, between FTS International, Inc. and Karen D. Thornton

10.8	***†	Letter Agreement, dated as of March 29, 2017, between FTS International, Inc. and Jennifer L. Keefe

10.9	***†	FTS International, Inc. 2014 Long-Term Incentive Plan

10.10	***†	Form of Restricted Stock Unit Agreement (Stock Settled) under the 2014 Long-Term Incentive Plan

10.11	***†	Description of 2016 Short-Term Incentive Plan

10.12	***†	Description of 2017 Short-Term Incentive Plan

10.13	***†	Form of Indemnification Agreement between FTS International, Inc. and each of its directors and executive officers

10.14	***	Master Service Agreement, dated as of July 9, 2012, by and between Chesapeake Operating, Inc. and FTS International Services, LLC

10.15	***	Master Commercial Agreement, dated as of December 24, 2016, by and between Chesapeake Operating, LLC and FTS International Services, LLC

10.16	***	Security Agreement, dated as of April 16, 2014, by and among FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC and U.S. Bank National Association, as collateral agent

10.17	***	Pari Passu Intercreditor Agreement, dated as of April 16, 2014, among FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC and U.S. Bank National Association, as collateral agent and Wells Fargo Bank, National Association, in its capacity as administrative agent for the Term Secured Parties (as defined therein)

10.18	***	Junior Lien Intercreditor Agreement, dated as of April 16, 2014, among FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC, Wells Fargo Bank, National Association in its capacity as administrative agent under the Term Loan Agreement, US Bank National Association, as collateral agent and Wells Fargo Bank, National Association, in its capacity as administrative agent for the ABL Secured Parties (as defined therein)

10.19	***	Junior Lien Intercreditor Agreement Joinder, dated as of June 1, 2015, among FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC, Wells Fargo Bank, National Association in its capacity as administrative agent under the Term Loan Agreement, US Bank National Association, as collateral agent and Wells Fargo Bank, National Association, in its capacity as administrative agent for the ABL Secured Parties (as defined in the Junior Lien Intercreditor Agreement)

10.20	***	Guaranty and Security Agreement, dated as of April 16, 2014, from FTS International, Inc., FTS International Services, LLC and FTS International Manufacturing, LLC to Wells Fargo Bank, National Association

10.21	***	Amended and Restated Trademark Security Agreement, dated as of June 22, 2015, from FTS International Services, LLC to Wells Fargo Bank, National Association pursuant to the Term Loan Agreement dated April 16, 2014

10.22	***	Amended and Restated Trademark Security Agreement, dated as of June 22, 2015, from FTS International Services, LLC to U.S. Bank National Association pursuant to the Indenture dated April 16, 2014

10.23	***	Amended and Restated Trademark Security Agreement, dated as of June 22, 2015, from FTS International Services, LLC to U.S. Bank National Association pursuant to the Indenture dated June 1, 2015

10.24	***†	FTS International, Inc. 2018 Equity and Incentive Compensation Plan

10.25	*†	Form of Restricted Stock Unit Agreement under the 2018 Equity and Incentive Compensation Plan

10.26	***†	First Amendment to Severance Agreement, dated as of June 15, 2017, between FTS International, Inc. and Michael J. Doss

10.27	***†	First Amendment to Severance Agreement, dated as of June 15, 2017, between FTS International, Inc. and Buddy Petersen

10.28	***†	First Amendment to Severance Agreement, dated as of June 15, 2017, between FTS International, Inc. and Lance Turner

10.29	***†	Letter Agreement, dated as of June 15, 2017, between FTS International, Inc. and Karen D. Thornton

10.30	***†	Letter Agreement, dated as of June 15, 2017, between FTS International, Inc. and Jennifer L. Keefe

10.31	***	Credit Agreement, dated February 22, 2018, among FTS International, Inc., Wells Fargo Bank, National Association, as administrative agent, and the several lenders party thereto

10.32	***	Guaranty and Security Agreement, dated February 22, 2018, among FTS International Services, LLC, FTS International, Inc., FTS International Manufacturing, LLC and Wells Fargo Bank, National Association, as administrative agent

10.33	***	Trademark Security Agreement, dated February 22, 2018, between FTS International Services, LLC and Wells Fargo Bank, National Association, as administrative agent

10.34	***	Junior Lien Intercreditor Agreement Joinder, dated as of February 22, 2018, between FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC, Wells Fargo Bank, National Association in its capacity as administrative agent under the Term Loan Agreement, US Bank National Association, as the notes collateral agent and Wells Fargo Bank, National Association, in its capacity as the ABL Facility Agent (as defined in the Junior Lien Intercreditor Agreement)

10.35	*†	Letter Agreement, dated December 19, 2016, between FTS International, Inc. and Karen D. Thornton

10.36	*†	Form of Restricted Stock Unit Agreement for Directors under the 2018 Equity and Incentive Compensation Plan

21.1	*	List of Subsidiaries

23.1	*	Consent of Grant Thornton LLP

24.1	*	Power of Attorney (included on signature page)

31.1	*	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	*	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	**	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

		Page
Cautionary Statement Regarding Forward-Looking Statements		ii

	PART I

Item 1.	Business	1
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	28
Item 2.	Properties	28
Item 3.	Legal Proceedings	29
Item 4.	Mine Safety Disclosures	29

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	31
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 8.	Financial Statements and Supplementary Data	43
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	43
Item 9A.	Controls and Procedures	43
Item 9B.	Other Information	43

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	44
Item 11.	Executive Compensation	49
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	62
Item 13.	Certain Relationships and Related Transactions, and Director Independence	64
Item 14.	Principal Accountant Fees and Services	66

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	67
	Index to Consolidated Financial Statements	F-1

		Page
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Statements of Operations		F-3
Consolidated Balance Sheets		F-4
Consolidated Statements of Cash Flows		F-5
Consolidated Statements of Stockholders’ Equity (Deficit)		F-6
Notes to Consolidated Financial Statements		F-7