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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on January 23, 2018

Registration No. 333-215998


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



Amendment No. 6
to

FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



FTS International, Inc.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  1389
(Primary Standard Industrial
Classification Code Number)
  30-0780081
(I.R.S. Employer
Identification Number)



777 Main Street, Suite 2900
Fort Worth, Texas 76102
(817) 862-2000
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)



Michael J. Doss
Chief Executive Officer
FTS International, Inc.
777 Main Street, Suite 2900
Fort Worth, Texas 76102
(817) 862-2000
(Name, address, including zip code, and telephone number, including area code, of agent for service)



Copies to:
Charles T. Haag
Edward B. Winslow
Jones Day
2727 North Harwood Street
Dallas, Texas 75201
(214) 220-3939
  Merritt S. Johnson
Shearman & Sterling LLP
599 Lexington Ave.
New York, New York 10022
(212) 848-4000



Approximate date of commencement of proposed sale to the public:
As soon as practicable after the effective date of this registration statement.



           If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box:    o

           If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering:    o

           If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering:    o

           If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering:    o

           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 Securities Exchange Act of 1934.

Large accelerated filer o

Smaller reporting company o

  Accelerated filer o

Emerging growth company ý

  Non-accelerated filer ý
(Do not check if a
smaller reporting company)

           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 7(a)(2)(B) of the Securities Act. ý

CALCULATION OF REGISTRATION FEE

               
 
Title of Each Class of Securities
to be Registered

  Amount to be
Registered(1)(2)

  Proposed Maximum
Offering Price Per
Share

  Proposed Maximum
Aggregate Offering
Price(1)(2)

  Amount of
Registration Fee(3)

 

Common Stock, $0.01 par value per share

  17,424,243   $18.00   $313,636,374   $39,048

 

(1)
Estimated solely for the purpose of computing the amount of the registration fee pursuant to Rule 457(o) under the Securities Act of 1933.

(2)
Includes the aggregate offering price of additional shares that the underwriters have the option to purchase.

(3)
Of this amount $11,590 was previously paid in connection with prior filings of this registration statement.

           The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

   


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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION DATED JANUARY 23, 2018

P R E L I M I N A R Y    P R O S P E C T U S

15,151,516 Shares

LOGO

FTS International, Inc.

Common Stock



        This is the initial public offering of shares of common stock of FTS International, Inc. We are selling 15,151,516 shares of our common stock.

        We expect the public offering price to be between $15.00 and $18.00 per share. Currently, no public market exists for the shares. After pricing of this offering, we expect that the shares will trade on The New York Stock Exchange, or NYSE, under the symbol "FTSI."

        We qualified as an "emerging growth company" as defined under the federal securities laws, at the time that we submitted to the SEC an initial draft of the registration statement for this offering, and, as such, have elected to comply with certain reduced disclosure requirements for this prospectus. However, our revenues for fiscal year 2017 exceeded $1.07 billion, and, as a result, we will no longer be eligible for the exemptions from disclosure provided to an emerging growth company after the earlier of the completion of this offering and December 31, 2018. See "Prospectus Summary—Implications of Being an Emerging Growth Company."

        Investing in our common stock involves risks that are described in the "Risk Factors" section beginning on page 18 of this prospectus.

 
  Price to
Public
  Underwriting
Discounts and
Commissions(1)
  Proceeds, before
expenses, to us
 

Per share

  $                 $                 $                

Total

  $                 $                 $                

(1)
See "Underwriting" for additional information regarding total underwriter compensation.

        The underwriters may also exercise their option to purchase up to an additional 2,272,727 shares from the Company, at the public offering price, less the underwriting discount, for 30 days after the date of this prospectus to cover over-allotments, if any.

        Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

        The underwriters expect to deliver the shares to purchasers on or about                  , 2018.

Credit Suisse

      Morgan Stanley
Wells Fargo Securities   Barclays   Citigroup   Evercore ISI
Guggenheim Securities   Simmons & Company International
Energy Specialists of Piper Jaffray
  Tudor, Pickering, Holt & Co.   Cowen

   

The date of this prospectus is                  , 2018.


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TABLE OF CONTENTS

PROSPECTUS SUMMARY

    1  

RISK FACTORS

    18  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

    38  

USE OF PROCEEDS

    41  

DIVIDEND POLICY

    42  

CAPITALIZATION

    43  

DILUTION

    45  

SELECTED FINANCIAL DATA

    47  

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

    51  

BUSINESS

    68  

MANAGEMENT

    88  

EXECUTIVE COMPENSATION

    98  

CERTAIN RELATIONSHIPS AND RELATED-PARTY TRANSACTIONS

    107  

PRINCIPAL STOCKHOLDERS

    110  

DESCRIPTION OF CAPITAL STOCK

    113  

DESCRIPTION OF INDEBTEDNESS

    117  

SHARES ELIGIBLE FOR FUTURE SALE

    120  

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS

    123  

UNDERWRITING

    127  

LEGAL MATTERS

    136  

EXPERTS

    136  

WHERE YOU CAN FIND MORE INFORMATION

    136  

INDEX TO FINANCIAL STATEMENTS

    F-1  

        We are responsible for the information contained in this prospectus and in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with information different from, or in addition to, that contained in this prospectus or any related free writing prospectus. We and the underwriters are offering to sell, and seeking offers to buy, these securities only in jurisdictions where offers and sales are permitted. The information in this prospectus or in any applicable free writing prospectus is accurate only as of its date, regardless of its time of delivery or any sale of these securities. Our business, financial condition, results of operations and prospects may have changed since that date.


Industry and Market Data

        The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.

        References to oil prices are to the spot price in U.S. Dollars per barrel of West Texas Intermediate, or WTI, an oil index benchmark used in the United States. References to natural gas prices are to the spot price in U.S. Dollars per one thousand cubic feet of natural gas using the Henry Hub index, a natural gas benchmark used in the United States.


Reverse Stock Split and Recapitalization

        Before this offering we will effect a 69.196592:1 reverse stock split, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. Upon filing our amended and restated certificate of incorporation, each 69.196592 shares of common stock will be combined into and represent one share of common stock. Additionally, before this offering our Series A convertible preferred stock, or our convertible preferred stock, will be recapitalized into shares of our common stock. Upon filing our amended and restated certificate of incorporation, all shares of convertible preferred stock will be recapitalized into 39,450,826.48 shares of common stock, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. Any change in the public offering price would change the number of shares outstanding prior to the completion of this offering by less than 1%. For additional information regarding the recapitalization of our convertible preferred stock, see

(i)


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"Description of Capital Stock." Following the reverse stock split and recapitalization, fractional shares will be paid out in cash.

        Following the reverse stock split and recapitalization, our authorized capital stock will consist of 320,000,000 shares of common stock and 25,000,000 shares of preferred stock and 91,280,087 shares of common stock will be outstanding, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. In connection with this offering, we will issue an additional 15,151,516 shares of new common stock and, immediately following this offering, we will have 106,431,603 total shares of common stock outstanding, assuming the underwriters do not exercise their option to purchase additional shares.


Comparability of Operating and Statistical Metrics

        Throughout this prospectus, we refer to "stages fractured" and similar terms, including "stages per active fleet." Stages fractured is an operating and statistical metric referring to the number of individual hydraulic fracturing procedures we complete under service contracts with our customers. Our customers typically compensate us based on the number of stages fractured. Stages per active fleet is an operating metric referring to the stages fractured per active fleet over a given time period. We believe stages fractured and stages per active fleet are important indicators of operating performance because they demonstrate the demand for our services and our ability to meet that demand with our active fleets. Because we service a variety of customers in different basins with different formation characteristics, stages fractured and stages per active fleet are subject to a number of material factors affecting their usefulness and comparability. For example, based on customer specifications and formation characteristics, some of our fleets may complete stages involving higher pressure job designs or more intense proppant loading, taking more time to complete, while other fleets may complete stages involving lower pressure job designs or less intense proppant loadings, taking less time to complete. Our fleets may also vary materially in hydraulic horsepower needed to accommodate the basin characteristics and customer specifications. For these reasons, stages fractured and stages per active fleet are not the only measures that affect our financial results, however, we believe they are important measures in managing our business. You should carefully read and consider the other information presented in this prospectus, including information under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and related notes included elsewhere in this prospectus.

(ii)


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PROSPECTUS SUMMARY

        This summary provides a brief overview of information contained elsewhere in this prospectus. This summary does not contain all the information that you should consider before investing in our common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings "Risk Factors," "Cautionary Note Regarding Forward-Looking Statements" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical consolidated financial statements and related notes thereto included elsewhere in this prospectus.

        Unless the context requires otherwise, references in this prospectus to "FTS International," "Company," "we," "us," "our" or "ours" refer to FTS International, Inc., together with its subsidiaries.

Our Company

        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, or 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. The following map shows the basins in which we operate and the number of fleets operated in each basin as of January 8, 2018.

GRAPHIC   GRAPHIC

        We have 1.6 million total hydraulic horsepower across 32 fleets, with 27 fleets active as of January 8, 2018. We are experiencing a surge in demand for our services, which has led us to reactivate 10 fleets since the beginning of 2017. Based on continued requests from customers for additional fleets, we are in the process of reactivating additional equipment at our in-house manufacturing facility. We believe we can reactivate all of our idle equipment for approximately $34 million, allowing us to further increase our operating fleets by five fleets, or approximately 19%, over the next nine months.

        The surge in demand for our services has allowed us to raise our prices significantly. Oil prices have more than doubled since the 12-year low of $26.14 in February 2016, reaching a high of $64.89 in January 2018 and averaging $50.80 in 2017. Similarly, the U.S. horizontal rig count has increased by

   

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155%, from a low of 314 rigs as of May 27, 2016 to 802 rigs as of January 19, 2018, according to an industry report. The large growth in E&P drilling activity has caused demand for pressure pumping services to exceed the supply of readily available fleets, which has led average pricing for our services to rise more than approximately 56% since the fourth quarter of 2016. These price increases started in January 2017 and continued to progress to higher levels throughout 2017.

        During the last two years, we implemented measures to reduce our operating costs and to improve our operating efficiency including reducing the number of our active fleet as demand for our services declined. We focused on our ability to operate our active fleets for as many hours per day and days per month as possible in order to limit the non-productive time of our active fleets. As a result, we have increased our average stages per active fleet per quarter to record levels. These operational improvements occurred despite significant reductions in our operating costs, including reducing our quarterly selling, general and administrative expense by approximately 60% from 2014 levels.

        We maintained these improved cost and efficiency levels in the fourth quarter of 2017, which, combined with the recent rise in pricing for our services, allowed us to achieve EBITDA levels greater than what we experienced in 2014. We achieved these results despite having considerably lower pricing and fewer active fleets on average than we had in 2014. We believe we can continue to sustain these cost reductions and efficiency improvements as activity levels increase.

        Our customers typically compensate us based on the number of stages fractured, and the primary contributor to the number of stages we complete is our ability to reduce downtime on our equipment. As a result, we believe the number of stages fractured and the average number of stages completed per active fleet in a given period of time are important operating metrics for our business. The graphs below show the number of stages we completed per quarter and the average stages per active fleet we completed per quarter. For additional information regarding our fleet capacity and average stages per active fleet per quarter as an operating metric, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Revenue" and "Business—Our Services—Hydraulic Fracturing."

GRAPHIC

        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 idle equipment. Our cost to produce components and reactivate 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. We estimate that our cost advantage saves us approximately $85 million per year at peak production levels. In addition, we designed and assembled all of our 32 existing fleets using internal resources, and we believe we could assemble new fleets internally at a substantial discount to the cost of buying them new from third-party providers.

        Our large scale and culture of innovation allow us to take advantage of leading technological solutions. We are focused on identifying new technologies aimed at: increasing fracturing effectiveness

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for our customers; reducing the operating costs of our equipment; and enhancing the health, safety and environmental, or HSE, conditions at our well sites. We have a number of ongoing initiatives that build on industry innovations and data analytics to achieve these technology objectives. We also conduct research and development activities 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.

Industry Overview and Trends

        The principal factor influencing demand for hydraulic fracturing services is the level of horizontal drilling activity by E&P companies in unconventional oil and natural gas reservoirs. Over the last decade, advances in drilling and completion technologies, including horizontal drilling and hydraulic fracturing, have encouraged E&P companies to focus on developing the vast oil and natural gas reserves contained within the U.S. basins in which we operate.

        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. As oil and natural gas prices have recovered from their 2016 lows, E&P companies in the United States have increased their level of horizontal drilling, resulting in an uptick in demand for hydraulic fracturing services that has strained available supply.

        Technological advances in oil and natural gas extraction continued through the downturn and have increased the efficiency of E&P companies, leading to an increase in demand for hydraulic fracturing units relative to each active drilling rig. In particular, drilling speeds have increased dramatically, allowing rigs to drill longer laterals in fewer days. The longer lateral lengths increase the demand for pressure pumping services relative to the rig count as evidenced by significant increases in both the number of stages per well and the amount of proppant used per well, particularly in recent years. As a result, E&P companies are able to complete more stages using fewer rigs, and many analysts expect demand for hydraulic fracturing services to significantly outpace growth in the horizontal rig count.

        In November 2016, May 2017 and November 2017, certain oil producing nations and the Organization of the Petroleum Exporting Countries, or OPEC, agreed to limit production of crude oil with the goal of raising oil prices. As a result, U.S. E&P companies have increased their level of horizontal drilling and completion activity and, hence, demand for hydraulic fracturing services has increased from the lows seen in mid-2016. This increase in demand has led to higher utilization, and in some cases shortages, of available horsepower. We believe the increase in activity coupled with an undersupply of available horsepower has particularly benefited us, and we believe all of our remaining inactive fleets can be returned to active service within nine months, if market conditions require.

Competitive Strengths

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

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

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an industry report from December 2017, these five operating basins will account for approximately 80% of well-completion 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 year ended December 31, 2016 and the nine months ended September 30, 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

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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.

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

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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 January 8, 2018. 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.

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.

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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

        We believe that our capital structure and liquidity upon completion of this offering will improve our financial flexibility to capitalize efficiently on our industry recovery, ultimately increasing value for our stockholders. To further improve our financial flexibility, we intend to enter into an asset-based revolving credit facility after the completion of this offering. 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 "Dividend Policy" and "Risk Factors" for more information.

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Selected Risks Associated with Our Business

        An investment in our common stock involves risks. You should carefully read and consider the information presented under the heading "Risk Factors" for an explanation of these risks before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment:

    The oil and natural gas industry is cyclical and prices are volatile. A reduction or sustained decline in oil and natural gas industry or prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.

    Competition intensified during the downturn and we rely upon a few customers for a significant portion of our revenues. Decreased demand for our services or the loss of one or more of these relationships could adversely affect our revenues.

    Our operations are subject to operational hazards for which we may not be adequately insured.

    Our operations are subject to various governmental regulations that require compliance that can be burdensome and expensive and may adversely affect the feasibility of conducting our operations.

    Any failure by us to comply with applicable governmental laws and regulations, including those relating to hydraulic fracturing, could result in governmental authorities taking actions that could adversely affect our operations and financial condition.

    We have substantial indebtedness and any failure to meet our debt obligations would adversely affect our liquidity and financial condition.

    Our major stockholders, Maju Investments (Mauritius) Pte Ltd, or Maju, CHK Energy Holdings, Inc., or Chesapeake, and Senja Capital Ltd, or Senja, will continue to exercise significant influence over matters requiring stockholder approval, and their interests may conflict with those of our other stockholders.

Implications of Being an Emerging Growth Company

        As a company with less than $1.07 billion in revenue during fiscal year 2016, we qualified as an "emerging growth company" as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act, at the time that we submitted to the SEC an initial draft of the registration statement for this offering, and, as such, have elected to comply with certain reduced disclosure requirements for this prospectus. These reduced reporting requirements include:

    reduced disclosure about our executive compensation arrangements; and

    the ability to present more limited financial data in the registration statement, of which this prospectus is a part.

        Our revenues for fiscal year 2017 exceeded $1.07 billion, and, as a result, we will no longer be eligible for the exemptions from disclosure provided to an emerging growth company after the earlier of the completion of this offering and December 31, 2018.

        We have elected to take advantage of all of the applicable JOBS Act provisions, except that we will elect to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised accounting standards (this election is irrevocable). Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

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Our Principal Stockholders

        Upon the recapitalization of our convertible preferred stock into common stock and the completion of this offering, Maju, Chesapeake and Senja will beneficially own approximately 39.1%, 24.8% and 11.2%, respectively, of our common stock, or 38.3%, 24.2% and 11.0%, respectively, if the underwriters exercise their option to purchase additional shares in full. For more information regarding our beneficial ownership see "Principal Stockholders."

        Maju is an indirect wholly owned subsidiary of Temasek Holdings (Private) Limited, or Temasek. Temasek is an investment company based in Singapore with a net portfolio of S$275 billion as of March 31, 2017. Chesapeake is a wholly owned subsidiary of Chesapeake Energy Corporation, or Chesapeake Parent. Established in 1989, Chesapeake Parent is an oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma. Senja is an investment company affiliated with RRJ Capital Limited, or RRJ. RRJ is an Asian investment firm with a total of assets under management of close to $11 billion.

        These stockholders will continue to exercise significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. See "Certain Relationships and Related Party Transactions—Investors' Rights Agreements." Furthermore, we anticipate that several individuals who will serve as our directors upon completion of this offering will be nominees of Maju, Chesapeake and Senja. See "Risk Factors—Our three largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders."

History and Conversion

        We were originally formed in 2000. In 2011, our prior majority owners sold their interest to a newly formed Delaware limited liability company controlled by an investor group comprised mainly of Maju, Chesapeake and Senja. We converted from a limited liability company to a corporation in 2012.

Company Information

        Our principal executive offices are located at 777 Main Street, Suite 2900, Fort Worth, Texas 76102, and our telephone number at that address is (817) 862-2000. Our website address is www.ftsi.com. Information contained on our website does not constitute part of this prospectus.

Recent Developments

Preliminary Estimate of Fourth Quarter 2017 Results

        Although our results of operations for the fourth quarter 2017 are not yet final, we have used the information available to us to provide an estimate of our results.

        Fourth quarter 2017 revenues are expected to be approximately $459 million. Costs of revenue, excluding depreciation and amortization, is expected to be approximately $300 million for the fourth quarter 2017.

        The Company deployed one additional fleet during the quarter and as of December 31, 2017 had 27 active fleets. The average number of active fleets during the fourth quarter of 2017 was 26.2.

        We are in the process of activating additional fleets due to increased customer demand. We expect our 28th fleet to be activated at the end of January 2018. We estimate the cost to reactivate our remaining five inactive fleets will be approximately $6.9 million per fleet, including capital expenditures, repairs charged as operating expense, labor costs, and other operating expenses. Some of these costs were already incurred at December 31, 2017.

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        The Company completed 8,248 stages in the fourth quarter of 2017. Activity levels were impacted by seasonal weather and holiday delays commonly experienced in the fourth quarter.

        The Company expects fourth quarter 2017 net income to be between $90 million and $95 million, up approximately 11% from the third quarter of 2017.

        Adjusted EBITDA is expected to be between $135 million and $140 million for the fourth quarter 2017, up approximately 8% from the third quarter of 2017.

        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 to Adjusted EBITDA:

 
  Three Months
Ended
December 31,
2017
   
 
 
  Three Months
Ended
September 30,
2017
 
(In millions)
  Low   High  

Net income

  $ 90.0   $ 95.0   $ 83.6  

Interest expense, net

    21.9     21.9     22.1  

Income tax expense

    0.4     0.6     0.4  

Depreciation and amortization

    21.4     21.4     22.1  

Loss (gain) on disposal of assets, net

    0.2     0.2     (0.8 )

Loss on extinguishment of debt

    1.4     1.4      

Adjusted EBITDA

  $ 135.3   $ 140.5   $ 127.4  

        Capital expenditures for the fourth quarter 2017 are expected to be approximately $30 million, which includes approximately $5 million in reactivation related capital expenditures and $10 million in growth related capital expenditures.

        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 the second half of 2018. Once completed, our total available fleet size would be 34 fleets representing 1.7 million hydraulic horsepower. We expect the total cost of these two additional fleets to be less than $50 million, some of which was already incurred at December 31, 2017.

        The preliminary financial information for, and as of the end of, the fourth quarter of 2017 included in this prospectus reflects management's estimates based solely upon information available to us as of the date of this prospectus and is the responsibility of management. The preliminary financial results presented herein are not a comprehensive statement of our financial results for the fourth quarter of 2017. In addition, the preliminary financial results presented herein, including the liquidity

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and capital resources table presented below, have not been audited, reviewed, or compiled by our independent registered public accounting firm, Grant Thornton LLP. Accordingly, Grant Thornton LLP does not express an opinion or any other form of assurance with respect thereto and assumes no responsibility for, and disclaims any association with, this information. The Company's actual results may differ materially from these preliminary financial results due to the completion of the Company's financial closing procedures, which have not yet been completed, final adjustments and other developments that may arise between the date of this prospectus and when results for the fourth quarter of 2017 are finalized. Our actual results for the fourth quarter of 2017 will not be available until after this offering is completed. Therefore, you should not place undue reliance upon these preliminary financial results. For instance, during the course of the preparation of the respective financial statements and related notes, additional items that would require material adjustments to be made to the preliminary estimated financial results presented above may be identified. There can be no assurance that these preliminary estimates will be realized, and estimates are subject to risks and uncertainties, many of which are not within our control. Accordingly, the preliminary estimated results discussed above may not be indicative of future results. See "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors."

Liquidity and Capital Resources

        During the fourth quarter of 2017, we retired $77.3 million of debt principal through optional redemptions and open market repurchases. At December 31, 2017, we had $208.1 million of cash and cash equivalents and total debt principal of $1,130 million. The following table summarizes our long-term debt:

(In millions)
  December 31,
2017
  September 30,
2017
 

Senior Secured 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 discounts and debt issuance costs

    (13.6 )   (15.7 )

Total long-term debt

  $ 1,116.4   $ 1,191.6  

        In addition to the debt repurchases during the fourth quarter of 2017, on January 17, 2018 we issued an unconditional notice to redeem an additional $60.0 million of our senior secured floating rate notes due June 15, 2020, or the 2020 Notes, on February 16, 2018. Within thirty days of the completion of this offering, the remaining $230.0 million of the 2020 Notes will be redeemed.

Asset-Based Revolving Credit Facility

        We intend to enter into a $250.0 million asset-based revolving credit facility following the consummation of this offering. We expect that we will enter into the credit facility upon redemption of the remaining 2020 Notes with the proceeds of this offering. We intend to use this facility for general working capital purposes in order to provide us with more flexibility and borrowing capacity.

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The Offering

Common stock offered by us

  15,151,516 shares.

Over-allotment option

 

We have granted the underwriters an option, exercisable for 30 days, to purchase up to an aggregate of 2,272,727 additional shares of our common stock to cover over-allotments, if any.

Common stock outstanding after this offering

 

106,431,603 shares or 108,704,330 shares if the underwriters exercise their option to purchase additional shares in full.

Use of proceeds

 

We expect to receive approximately $233.4 million (or approximately $268.9 million if the underwriters' option to purchase additional shares in this offering is exercised in full) of net proceeds from the sale of the common stock offered by us, assuming an initial public offering price of $16.50 per share, the midpoint of the price range set forth on the cover page of this prospectus, after deducting underwriting discounts and commissions and estimated offering expenses. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $14.4 million.

 

We intend to use the net proceeds from this offering for general corporate purposes, which will include repaying indebtedness under the 2020 Notes. See "Use of Proceeds."

Dividend policy

 

After the completion of this offering, we intend to retain future earnings, if any, for use in the repayment of our existing indebtedness and in the operation and expansion of our business. Therefore, we do not anticipate paying any cash dividends in the foreseeable future following this offering. See "Dividend Policy."

Listing and trading symbol

 

After pricing of this offering, we expect that our shares will trade on the NYSE under the symbol "FTSI."

Directed Share Program

 

At our request, the underwriters have reserved up to 5.0% of the common stock being offered by this prospectus for sale to our directors, executive officers, employees, business associates and related persons at the public offering price. The sales will be made by the underwriters through a directed share program. The number of shares of common stock available for sale to the general public will be reduced to the extent these individuals purchase such reserved shares. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same basis as the other shares offered by this prospectus. These persons must commit to purchase no later than the close of business on the day following the date of this prospectus. Any directors or executive officers purchasing such reserved common stock will be prohibited from selling such stock for a period of 180 days after the date of this prospectus. The directed share program will be arranged through Morgan & Stanley & Co. LLC.

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Risk Factors

 

You should carefully read and consider the information beginning on page 18 of this prospectus set forth under the heading "Risk Factors" and all other information set forth in this prospectus before deciding to invest in our common stock.

        Before this offering we will effect a 69.196592:1 reverse stock split, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. Upon filing our amended and restated certificate of incorporation, each 69.196592 shares of common stock will be combined into and represent one share of common stock. Additionally, before this offering our convertible preferred stock will be recapitalized into 39,450,826.48 shares of common stock, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. A change in the public offering price would change the number of shares outstanding prior to the completion of this offering by less than 1%. For additional information regarding the recapitalization of our convertible preferred stock, see "Description of Capital Stock." Following the reverse stock split and recapitalization, fractional shares will be paid out in cash.

        Following the reverse stock split and recapitalization, our authorized capital stock will consist of 320,000,000 shares of common stock and 25,000,000 shares of preferred stock and 91,280,087 shares of common stock will be outstanding, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. In connection with this offering, we will issue an additional 15,151,516 shares of new common stock and, immediately following this offering, we will have 106,431,603 total shares of common stock outstanding, assuming the underwriters do not exercise their option to purchase additional shares.

        Unless otherwise noted, all information contained in this prospectus:

    Assumes the underwriters do not exercise their option to purchase additional shares;

    Other than historical financial data, reflects (1) our 69.196592:1 reverse stock split and (2) the recapitalization of our convertible preferred stock into 39,450,826.48 shares of common stock, in each case, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus; and

    Excludes shares of common stock reserved for issuance under the FTS International, Inc. 2014 Long-Term Incentive Plan, or the 2014 LTIP and under the FTS International, Inc. 2018 Equity and Incentive Compensation Plan, or the 2018 Plan.

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SUMMARY FINANCIAL DATA

        The following tables set forth our summary historical consolidated financial data for the periods and the dates indicated. The consolidated statements of operations data for the years ended December 31, 2015 and 2016 and the consolidated balance sheet data as of December 31, 2015 and 2016 are derived from our audited consolidated financial statements, or Audited Consolidated Financial Statements, that are included elsewhere in this prospectus. The consolidated statements of operations data for the nine months ended September 30, 2016 and 2017 and the consolidated balance sheet data as of September 30, 2017 are derived from our unaudited consolidated financial statements, or Unaudited Consolidated Financial Statements, that are included elsewhere in this prospectus. The results of operations for the periods presented below are not necessarily indicative of the results to be expected for any future period, and the results for any interim period are not necessarily indicative of the results that may be expected for a full fiscal year.

        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 prospectus.

 
  Year Ended
December 31,
  Nine Months Ended
September 30,
 
(Dollars in millions, except per share amounts)
  2015   2016   2016   2017  

Statements of Operations Data:

                         

Revenue

  $ 1,375.3   $ 532.2   $ 379.8   $ 1,007.4  

Costs of revenue, excluding depreciation and amortization(1)

    1,257.9     510.5     369.7     709.9  

Selling, general and administrative

    154.7     64.4     51.5     62.0  

Depreciation and amortization

    272.4     112.6     87.5     65.2  

Impairments and other charges(2)

    619.9     12.3     10.7     1.4  

Loss (gain) on disposal of assets, net

    5.9     1.0     1.1     (1.6 )

Gain on insurance recoveries

        (15.1 )   (15.1 )   (2.9 )

Operating income (loss)

    (935.5 )   (153.5 )   (125.6 )   173.4  

Interest expense, net

    77.2     87.5     66.1     64.8  

Loss (gain) on extinguishment of debt, net

    0.6     (53.7 )   (53.7 )    

Equity in net loss (income) of joint venture affiliate

    1.4     2.8     2.6     (0.1 )

Income (loss) before income taxes

    (1,014.7 )   (190.1 )   (140.6 )   108.7  

Income tax expense (benefit)(3)

    (1.5 )   (1.6 )       0.9  

Net income (loss)

  $ (1,013.2 ) $ (188.5 ) $ (140.6 ) $ 107.8  

Net loss attributable to common stockholders

  $ (1,158.1 ) $ (370.1 ) $ (272.7 ) $ (56.8 )

Basic and diluted earnings (loss) per share attributable to common stockholders

  $ (0.32 ) $ (0.10 ) $ (0.08 ) $ (0.02 )

Shares used in computing basic and diluted earnings (loss) per share (in millions)

    3,589.7     3,586.5     3,586.5     3,586.4  

Balance Sheet Data (at end of period):

                         

Cash and cash equivalents

  $ 264.6   $ 160.3         $ 193.8  

Total assets

  $ 907.4   $ 616.8         $ 827.1  

Total debt

  $ 1,276.2   $ 1,188.7         $ 1,191.6  

Convertible preferred stock(4)

  $ 349.8   $ 349.8         $ 349.8  

Total stockholders' equity (deficit)

  $ (830.5 ) $ (1,019.0 )       $ (911.2 )

Pro Forma Data(5):

                         

Pro forma net income (loss)

        $ (168.3 )       $ 123.7  

Pro forma basic and diluted earnings (loss) per share attributable to common stockholders

        $ (1.58 )       $ 1.16  

Pro forma shares used in computing basic and diluted earnings (loss) per share (in millions)(6)

          106.5           106.5  

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  Year Ended
December 31,
  Nine Months Ended
September 30,
 
(Dollars in millions, except per share amounts)
  2015   2016   2016   2017  

Pro forma total debt (at end of period)

                    $ 847.2  

Pro forma total stockholders' equity (deficit) (at end of period)

                    $ (342.6 )

Other Data:

                         

Adjusted EBITDA(7)

  $ (62.8 ) $ (50.8 ) $ (47.7 ) $ 234.2  

Net debt (at end of period)(8)

  $ 1,011.6   $ 1,028.4                    $ 997.8  

Pro forma net debt (at end of period)(8)

                    $ 779.0  

Capital expenditures

  $ 79.1   $ 10.3   $ 6.1   $ 33.4  

Total fracturing stages(9)

    21,919     16,185     11,135     22,672  

(1)
The amount of depreciation and amortization related to our costs of revenue that has been classified as depreciation and amortization in this table for the year ended December 31, 2015 and 2016 is $152.3 million and $98.9 million, respectively, and for the nine months ended September 30, 2016 and 2017 is $76.9 million and $56.7 million, respectively.

(2)
For a discussion of amounts recorded for the years ended December 31, 2015 and 2016 and for the nine months ended September 30, 2016 and 2017, see Note 10—"Impairments and Other Charges" in Notes to our Audited Consolidated Financial Statements included elsewhere in this prospectus and Note 4—"Impairments and Other Charges" in Notes to our Unaudited Condensed Consolidated Financial Statements included elsewhere in this prospectus.

(3)
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.

(4)
The holders of the convertible preferred stock are also common stockholders of the Company and collectively appoint 100% of our board of directors. Therefore, the convertible preferred stockholders can direct the Company to redeem the convertible preferred stock at any time after all of our debt has 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 7—"Convertible Preferred Stock" in Notes to our Audited Consolidated Financial Statements included elsewhere in this prospectus for more information. At September 30, 2017, the liquidation preference of the convertible preferred stock was estimated to be $1,070.7 million.

(5)
Pro forma data gives effect to (1) the 69.196592:1 reverse stock split, (2) the recapitalization of our convertible preferred stock into issued and outstanding common stock, (3) the sale of 15,151,516 shares of common stock to be issued by us in this offering (assuming the underwriters do not exercise their option to purchase additional shares) and (4) the use of proceeds therefrom, as if each of these events occurred on January 1, 2016 for purposes of the statement of operations and September 30, 2017, for purposes of the balance sheet, and for each of (1), (2), (3) and (4), assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. Additionally, the pro forma balance sheet information reflects a share-based compensation expense of approximately $3.7 million associated with restricted stock units issued under our 2014 LTIP that will vest immediately before effectiveness of the registration statement, of which this prospectus is a part, and will be settled in cash. Any change in the public offering price would change the number of shares outstanding prior to the completion of this offering by less than 1%. For additional information regarding the recapitalization of our convertible preferred stock, see "Description of Capital Stock."

(6)
The pro forma shares used to compute pro forma earnings per share for the year ended December 31, 2016 and the nine months ended September 30, 2017, have been adjusted to include the sale of 15,151,516 shares of common stock in this offering (assuming the underwriters do not exercise their option to purchase additional shares) that would generate only enough proceeds to repay debt as described under "Use of Proceeds."

(7)
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

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    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,
  Nine Months
Ended
September 30,
 
(In millions)
  2015   2016   2016   2017  

Net income (loss)

  $ (1,013.2 ) $ (188.5 ) $ (140.6 ) $ 107.8  

Interest expense, net

    77.2     87.5     66.1     64.8  

Income tax expense (benefit)

    (1.5 )   (1.6 )       0.9  

Depreciation and amortization

    272.4     112.6     87.5     65.2  

Loss (gain) on disposal of assets, net

    5.9     1.0     1.1     (1.6 )

Loss (gain) on extinguishment of debt, net

    0.6     (53.7 )   (53.7 )    

Inventory write-down

    24.5              

Impairment of assets and goodwill

    572.9     7.0     7.0      

Gain on insurance recoveries

        (15.1 )   (15.1 )   (2.9 )

Acquisition earn-out adjustments

    (3.4 )            

Stock-based compensation

    1.8              

Adjusted EBITDA

  $ (62.8) (a) $ (50.8) (b) $ (47.7) (c) $ 234.2 (d)

(a)
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.

(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.

(c)
For the nine months ended September 30, 2016, Adjusted EBITDA has not been adjusted to exclude the following items: employee severance costs of $0.8 million, supply commitment charges of $1.5 million and lease abandonment charges of $1.4 million.

(d)
For the nine months ended September 30, 2017, Adjusted EBITDA has not been adjusted to exclude a supply commitment charge of $1.0 million.
(8)
Net debt is a non-GAAP financial measure that we define as total debt less cash and cash equivalents. The most comparable financial measure to net debt under GAAP is debt. Net debt is used by management as a measure of our financial leverage. Net debt should not be used by investors or others as the sole basis in formulating investment decisions as it does not represent our actual indebtedness. Pro forma net debt is net debt adjusted as if we received the net proceeds from this offering and we (a) settled the restricted stock units granted under the 2014 LTIP in cash and (b) redeemed $350.0 million of our outstanding 2020 Notes as if each of these events occurred on September 30, 2017.

The following table reconciles our total debt to net debt:

 
  As of
December 31,
  As of
September 30,
 
(In millions)
  2015   2016   2017  

Total debt

  $ 1,276.2   $ 1,188.7   $ 1,191.6  

Cash and cash equivalents

    (264.6 )   (160.3 )   (193.8 )

Net debt

  $ 1,011.6   $ 1,028.4   $ 997.8  

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    The following table reconciles our total debt to pro forma net debt:

(In millions)
  As of
September 30, 2017
 

Total debt

  $ 1,191.6  

Repayment of 2020 Notes

    (344.4 )

Pro forma total debt

    847.2  

Cash and cash equivalents

    193.8  

Net proceeds from this offering

    233.4  

Cash settlement of 2014 restricted stock units

    (3.7 )

Cash paid to repurchase 2020 Notes

    (355.3 )

Pro forma cash and cash equivalents

    68.2  

Pro forma net debt

  $ 779.0  
(9)
See "Business—Our Services—Hydraulic Fracturing" for details regarding fracturing stages and fleets and the types of agreements we use to provide hydraulic fracturing services.

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RISK FACTORS

        An investment in our common stock involves risks. You should carefully consider the risks and uncertainties described below, together with all of the other information contained in this prospectus, including the section titled "Management's Discussion and Analysis of Financial Condition and Results of Operation" and our consolidated financial statements and the related notes, before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

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 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.

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        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 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.

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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 year ended December 31, 2016 and the nine months ended September 30, 2017, our four largest customers generated approximately 52% and 33%, 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."

        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.

        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.

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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.

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        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 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

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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 effect 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, or 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 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, or 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

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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, or 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, or 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, or 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, 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

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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.

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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.

        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

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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 $10.3 million and $33.4 million, respectively, for the year ended December 31, 2016 and the nine months ended September 30, 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 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.

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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.

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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.

Adverse weather conditions could impact demand for our services or impact our costs.

        Our business could be adversely affected by adverse weather conditions. For example, unusually warm winters could adversely affect the demand for our services by decreasing the demand for natural gas or unusually cold winters could adversely affect our capability to perform our services, for example, due to delays in the delivery of equipment, personnel and products that we need in order to provide our services and weather-related damage to facilities and equipment, resulting in delays in operations. Our operations in arid regions can be affected by droughts and limited access to water used in our hydraulic fracturing operations. These constraints could adversely affect the costs and results of operations.

A terrorist attack or armed conflict could harm our business.

        Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if wells, operations sites or other related facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our products and services. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

International operations subject us to additional economic, political and regulatory risks.

        In February 2016, our joint venture with the Sinopec Group, or Sinopec, commenced hydraulic fracturing operations in China. International operations require significant resources and may result in foreign operations that ultimately are not successful. Our joint venture operations and any further international expansion expose us to operational risks, including exposure to foreign currency rate fluctuations, war or political instability, limitations on the movement of funds, foreign and domestic government regulation, including compliance with the U.S. Foreign Corrupt Practices Act, and bureaucratic delays. These may increase our costs and distract key personnel, which may adversely affect our business, financial condition or results of operations.

Our ability to utilize our net operating loss carryforwards and certain tax amortization deductions may be delayed or limited.

        As of December 31, 2016, we had federal and state net operating loss carryforwards, or NOLs, of approximately $1,600 million and $628 million, respectively, which if not utilized will begin to expire starting in 2032 for federal purposes and 2017 for state purposes. We may use these NOLs to offset against taxable income for U.S. federal and state income tax purposes. Additionally, we are allowed to deduct approximately $190 million of amortization expense on our federal and state tax returns per

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year for tax years 2017 through 2025. However, Section 382 of the Internal Revenue Code of 1986, as amended, may reduce the amount of the NOLs we may use or tax amortization we may deduct for U.S. federal income tax purposes in the event of certain changes in ownership of our Company. A Section 382 "ownership change" generally occurs if one or more stockholders or groups of stockholders who own at least 5% of a company's stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three year period—for example, if we and/or our three largest stockholders were to sell shares of our common stock, so that following such offering, the public owned more than 50% of our common stock. Similar rules may apply under state tax laws. This offering or future issuances or sales of our stock, including by our large stockholders or certain other transactions involving our stock that are outside of our control, could cause an "ownership change." If an "ownership change" has occurred in the past or occurs in the future, including in connection with this offering, Section 382 would impose an annual limit on the amount of pre-ownership change NOLs and other tax attributes, including potentially a portion of our tax amortization deduction, that we can use to reduce our taxable income, potentially increasing and accelerating our liability for income taxes, and also potentially causing those tax attributes to expire unused. Any limitation of our tax amortization dedution or NOLs could, depending on the extent of such limitation and the NOLs previously used, result in our retaining less cash after payment of U.S. federal and state income taxes during any year in which we have taxable income, rather than losses, than we would be entitled to retain if such NOLs or tax amortization deductions were not reduced as an offset against such income for U.S. federal and state income tax reporting purposes, which could adversely impact our operating results.

Risks Relating to Our Indebtedness

We have substantial indebtedness. Any failure to meet our debt obligations would adversely affect our liquidity and financial condition.

        At September 30, 2017, we had $1.2 billion of long-term indebtedness outstanding. Our indebtedness affects our operations in several ways, including the following:

    a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

    the covenants contained in the debt agreements governing our outstanding indebtedness limit our ability to borrow additional funds, and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and

    a lowering of the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing.

        If our cash flow and other capital resources are insufficient to fund our obligations under our debt agreements on a current basis and at maturity, or if we are otherwise unable to comply with the covenants in those agreements, we will need to refinance or restructure our debt. The proceeds of future borrowings may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all. In addition, if we finance our operations through additional indebtedness, then the risks that we now face relating to our current debt level would intensify, and it would be more difficult to satisfy our existing financial obligations. Furthermore, if a default occurs under one debt agreement, then this could cause a cross-default under other debt agreements.

        We intend to use the net proceeds from this offering for general corporate purposes, which will include repaying indebtedness under our 2020 Notes. See "Use of Proceeds."

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Liquidity is essential to our business, and it has been and may continue to be adversely affected.

        Liquidity is essential to our business to service our debt and purchase the labor, materials and equipment that we use to operate our business. Additionally, we believe that a service provider's liquidity is important to our customers because adequate liquidity provides assurance that a service provider will have the financial resources to continue to operate in challenging industry conditions.

        Our liquidity was adversely affected by the industry downturn due to the low or non-existent profit margins for utilization of our services. Our liquidity may be further impaired by unforeseen cash expenditures, which may arise due to circumstances beyond our control.

        Additionally, the terms of our existing debt instruments restrict, and any future debt instruments may further restrict, our ability to incur additional indebtedness, sell certain assets and engage in certain business activities. These restrictions prohibit activities that we could use to increase our liquidity. Also, our current lenders and investors hold a first lien on a portion of our assets as collateral, including substantially all of our revenue-generating equipment. New lenders and investors may require additional collateral, which could additionally impair our access to liquidity. If alternate financing is not available on favorable terms or at all, we would be required to decrease our capital spending to an even greater extent. Any additional decrease in our capital spending would adversely affect our ability to sustain or improve our profits. Refinancing may not be available, and any refinancing of our debt could be at higher interest rates, which could further adversely affect our liquidity.

Increases in interest rates could negatively affect our financing costs and our ability to access capital.

        We have exposure to future interest rates based on the variable rate debt under our term loan due April 16, 2021, or the Term Loan, and 2020 Notes and to the extent we raise additional debt in the capital markets at variable rates, including any future revolving credit facility, to meet maturing debt obligations or to fund our capital expenditures and working capital needs. Daily working capital requirements are typically financed with operational cash flow and through the use of our existing borrowings. The interest rate on the Term Loan and the 2020 Notes is generally determined from the applicable LIBOR rate at the borrowing date plus a pre-set margin. We are therefore subject to market interest rate risk on that portion of our long-term debt that relates to the Term Loan and 2020 Notes. We do not employ risk management techniques, such as interest rate swaps, to hedge against interest rate volatility, and accordingly significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results.

Risks Relating to this Offering and 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.

        Prior to the completion of this offering and the recapitalization of our convertible preferred stock, (1) Maju, an indirect wholly owned subsidiary of Temasek, (2) Chesapeake, a wholly owned subsidiary of Chesapeake Parent, and (3) Senja, an investment company affiliated with RRJ, beneficially own 40.7%, 30.3% and 11.2%, respectively, of our common stock and 50.7%, 30.0% and 13.87%, respectively, of our convertible preferred stock. Upon completion of this offering and the recapitalization of the preferred stock into common stock, Maju, Chesapeake and Senja will beneficially own approximately 39.1%, 24.8% and 11.2%, respectively, of our common stock, or 38.3%, 24.2% and 11.0%, respectively, if the underwriters exercise their option to purchase additional shares in full. See "Principal Stockholders." As a result, Maju, Chesapeake and Senja, together, will continue to exercise significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. Furthermore, we anticipate that several individuals who will serve as our directors upon completion of this offering will

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be 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 Party Transactions" and "Principal Stockholders." Furthermore, prior to completion of this offering, we will enter into investors' rights agreements with Maju, Chesapeake, Senja and Hampton Asset Holding Ltd., or Hampton, which will contain agreements regarding, among other things, director nomination, information and observer rights. See "Certain Relationships and Related Party Transactions—Investors' Rights Agreements." 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 you to receive any related takeover premium for your 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."

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active liquid trading market for our common stock may not develop and our stock price may be volatile.

        Prior to this offering, our equity securities were not traded on any market. An active and liquid trading market for our common stock may not develop or be maintained after this offering. 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, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us and representatives of the underwriters, based on numerous factors that we discuss in the "Underwriting" section of this prospectus, and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

        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;

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    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.

Purchasers of common stock in this offering will experience immediate and substantial dilution.

        Based on an assumed initial public offering price of $16.50 per share, the midpoint of the price range set forth on the cover page of this prospectus, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $20.09 per share in the pro forma as adjusted net tangible book value per share of our common stock from the initial public offering price. Our pro forma as adjusted net tangible book value as of September 30, 2017 after giving effect to this offering would be $(3.59) per share. See "Dilution" for a complete description of the calculation of net tangible book value.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the requirements of the Sarbanes-Oxley Act of 2002, or 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 will 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, or the SEC, and the requirements of the national stock exchange on which our common stock is listed, with which we are 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 PCAOB;

    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, we also expect that being a public company subject to these rules and regulations will require us to obtain increased director and officer liability insurance coverage and we may be required

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to incur 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.

We qualified as an emerging growth company at the time that we submitted to the SEC an initial draft of the registration statement for this offering, and as a result have certain reduced disclosure requirements in this prospectus.

        We qualified as an emerging growth company, as defined in the JOBS Act, at the time that we submitted to the SEC an initial draft of the registration statement for this offering, and, as a result, have elected to comply with certain reduced disclosure requirements for this prospectus in accordance with the JOBS Act. With the reduced disclosure requirement, we are not required to disclose certain executive compensation information in this prospectus pursuant to the JOBS Act. We also are required to present only two years of audited financial statements and related "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this prospectus. Our revenues for 2017 exceeded $1.07 billion, however, and, as a result, we will no longer be eligible for the exemptions from disclosure provided to an emerging growth company after the earlier of the completion of this offering and December 31, 2018.

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 will:

    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 will enter into with Maju, Chesapeake, Senja and Hampton prior to the completion of this offering, 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;

    restrict the forum for certain litigation against us to Delaware;

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    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, or 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 will provide substantially the same limitations as are set forth in Section 203 but will also provide 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 may be unsuccessful in implementing required internal controls over financial reporting.

        We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the applicable SEC rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

        We are in the process of evaluating our internal control systems to allow management to report on our internal controls over financial reporting. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and PCAOB rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a "material weakness" or changes in internal controls that materially affect, or are reasonably likely to materially affect, internal controls over financial reporting. The PCAOB has defined a material weakness as a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material

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misstatement of the company's annual or interim financial statements will not be prevented, or detected and subsequently corrected, on a timely basis.

        Our efforts to develop and maintain effective internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Any failure to remediate future deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanctions or investigations by the SEC, the national stock exchange on which we listed our common stock or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

We may not pay dividends on our common stock and, consequently, you would achieve a return on your 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 and the indentures governing our 2020 Notes and our 6.250% senior secured notes due May 1, 2022, or the 2022 Notes. If we do not make cash distributions to stockholders or otherwise return cash to stockholders, a return on your investment in us will only be achieved if the market price of our common stock appreciates, which may not occur, and you sell your shares at a profit. There is no guarantee that the price of our common stock in the market after this offering will exceed the price that you pay. See "Dividend Policy."

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 your 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. We also intend to register shares of common stock that we have granted as equity awards or may grant as equity awards under our 2018 Plan. Once we register these shares, they will be able to be sold freely in the public market, subject to volume limitations applicable to affiliates, applicable vesting periods and lock-up agreements. Upon the completion of this offering, we will have 106,431,603 outstanding shares of common stock. This number includes 15,151,516 shares that we are selling in this offering, which may be resold immediately in the public market. Following the completion of this offering, certain of our affiliates will own 75.9% of our outstanding shares of common stock, consisting of 80,816,251 shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in "Underwriting," but may be sold into the market in the future.

        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 will rely in part on the research and reports that industry or financial analysts publish about us or our business. We do not control these analysts.

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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 will authorize 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.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        This prospectus contains "forward-looking statements" that are subject to risks and uncertainties. All statements other than statements of historical or current fact included in this prospectus 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. You can identify forward-looking statements 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, you 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 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;

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    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;

    introduction of new drilling or completion techniques, or services using new technologies subject to patent or other intellectual property protections;

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

    loss or corruption of our information or a cyberattack on our computer systems;

    one or more of our directors may not reside in the United States limiting the ability of investors from obtaining or enforcing judgments against them;

    adverse weather conditions causing stoppage or delay in operations;

    a terrorist attack or armed conflict disrupting operations;

    additional economic, political and regulatory risks related to international operations;

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

    our ability to utilize our net operating losses;

    our inability to service our debt obligations;

    adverse effects on our financial strategy and liquidity;

    increases in interest rates; and

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

        We make many of our forward-looking statements based on our operating budgets and forecasts, which are based upon detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and it is impossible for us to anticipate all factors that could affect our actual results.

        See the "Risk Factors" section of this prospectus for a more complete discussion of the risks and uncertainties mentioned above and for discussion of other risks and uncertainties we face that could cause our forward-looking statements to be inaccurate. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements as well as others made in this

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prospectus and hereafter in our other SEC filings and public communications. You should evaluate all forward-looking statements made by us in the context of these risks and uncertainties.

        We caution you that the risks and uncertainties identified by us may not be all of the factors that are important to you. Furthermore, the forward-looking statements included in this prospectus are made only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statement as a result of new information, future events or otherwise, except as required by law.

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USE OF PROCEEDS

        We estimate that we will receive net proceeds of approximately $233.4 million from our sale of 15,151,516 shares of our common stock in this offering, assuming an initial public offering price of $16.50 per share, the midpoint of the price range set forth on the cover page of this prospectus, after deducting underwriting discounts and commissions and estimated offering expenses of approximately $16.6 million. If the over-allotment option that we have granted to the underwriters is exercised in full, we estimate that the net proceeds to us will be approximately $268.9 million.

        Each $1.00 increase (decrease) in the assumed initial public offering price of $16.50 per share, the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) the net proceeds to us by approximately $14.4 million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, and after deducting underwriting discounts and commissions and estimated offering expenses.

        We intend to use the net proceeds from this offering for general corporate purposes, which will include repaying indebtedness under our 2020 Notes as set forth below:

        The 2020 Notes bear interest at a rate per annum equal to LIBOR plus a margin of 7.500% per annum. The 2020 Notes mature on June 15, 2020. We have provided two notices to the holders of the 2020 Notes, (a) for redemption of $60.0 million aggregate principal amount and (b) for redemption of the remaining $230.0 million aggregate principal amount, and in the case of (b), subject to completion of this offering and the closing of an asset-based credit facility on satisfactory terms. We will redeem the notes at a redemption price of 101.500% of the principal amount, plus accrued and unpaid interest to, but not including the redemption date.

        See "Description of Indebtedness" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" for additional information regarding our indebtedness and a discussion of our capital needs for the next 12 months.

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DIVIDEND POLICY

        We currently intend to retain the majority of future earnings, if any, for use in the repayment of our existing indebtedness and in the operation and expansion of our business. Therefore, we may not pay any cash dividends. The declaration and payment of future cash dividends will be at the sole discretion of our board of directors, subject to applicable laws. Any decision to pay future cash dividends will depend upon various factors, including our results of operations, financial condition, capital requirements, contractual restrictions with respect to the payment of dividends, investment opportunities and other factors that our board of directors may deem relevant. Our Term Loan and indentures governing our 2020 Notes and 2022 Notes contain restrictions and any future agreements may contain restrictions on our ability to pay dividends or make any other distribution or payment on account of our common stock.

        For additional information regarding our indebtedness, see "Description of Indebtedness."

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CAPITALIZATION

        The following table sets forth our cash and cash equivalents and capitalization as of September 30, 2017:

    on an actual basis;

    on a pro forma basis to give effect to (1) our 69.196592:1 reverse stock split and (2) the recapitalization of all of our convertible preferred stock into shares of our common stock as if all of the foregoing events had occurred on September 30, 2017, in each case, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus; and

    on a pro forma as adjusted basis to give further effect to (1) the sale of shares of common stock in this offering (assuming the underwriters do not exercise their option to purchase additional shares) at an assumed initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover of this prospectus, after deducting underwriting discounts and commissions and estimated fees and expenses, (2) the repayment of $350.0 million principal amount of our long-term debt, which would have resulted in a loss on debt extinguishment of $10.9 million and (3) a share-based compensation expense of approximately $3.7 million associated with restricted stock units that will vest immediately before effectiveness of the registration statement, of which this prospectus is a part, as if all of the foregoing events had occurred on September 30, 2017.

        You should read the following table in conjunction with "Use of Proceeds," "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," and our consolidated financial statements and related notes included elsewhere in this prospectus.

 
  As of September 30, 2017  
(In millions)
  Actual   Pro Forma   Pro Forma
As Adjusted(1)
 

Cash and cash equivalents

  $ 193.8   $ 193.8   $ 68.2  

Long-term debt:

                   

2020 Notes

    350.0     350.0      

Term Loan

    431.0     431.0     431.0  

2022 Notes

    426.3     426.3     426.3  

Total principal amount

    1,207.3     1,207.3     857.3  

Less unamortized discount and debt issuance costs

    (15.7 )   (15.7 )   (10.1 )

Total long-term debt

  $ 1,191.6   $ 1,191.6   $ 847.2  

Series A convertible preferred stock, par value $0.01(2)

    349.8          

Stockholders' equity(3):

                   

Common stock, par value $0.01

    35.9     36.3     36.5  

Additional paid-in capital

    3,712.1     4,061.5     4,294.7  

Accumulated deficit

    (4,659.2 )   (4,659.2 )   (4,673.8 )

Total stockholders' deficit

    (911.2 )   (561.4 )   (342.6 )

Total capitalization

  $ 630.2   $ 630.2   $ 504.6  

(1)
A $1.00 increase (decrease) in the assumed initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover of this prospectus, would increase

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    (decrease) cash and cash equivalents, total stockholders' deficit and total capitalization by $14.4 million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting underwriting discounts and commissions and estimated offering expenses.

(2)
The holders of the convertible preferred stock are also common stockholders of the Company and collectively appoint 100% of our board of directors. Therefore, the convertible preferred stockholders can direct the Company to redeem the convertible preferred stock at any time after all of our debt has been repaid; however, we did not consider this to be probable for the period presented due to the amount of debt outstanding. Therefore, we have presented the convertible preferred stock as temporary equity, but we have not reflected any accretion of the convertible preferred stock in this table or in our Consolidated Financial Statements. See Note 7—"Convertible Preferred Stock" in Notes to our Audited Consolidated Financial Statements included elsewhere in this prospectus for more information. At September 30, 2017, the liquidation preference of the convertible preferred stock was estimated to be $1,070.7 million.

(3)
As of September 30, 2017, our authorized capital stock consisted of 5,000,000,000 shares of common stock and 350,000 shares of our convertible preferred stock and 3,586,408,881 shares of common stock and 350,000 shares of convertible preferred stock were issued and outstanding. Before this offering (1) we will effect a 69.196592:1 reverse stock split and (2) all shares of our convertible preferred stock will be recapitalized into 39,450,826.48 shares of common stock, in each case, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. A change in the public offering price would change the number of shares outstanding prior to the completion of this offering by less than 1%. For additional information regarding the recapitalization of our convertible preferred stock, see "Description of Capital Stock." Following the reverse stock split and recapitalization, our authorized capital stock will consist of 320,000,000 shares of common stock and 25,000,000 shares of preferred stock and 91,280,087 shares of common stock will be outstanding. In connection with this offering, we will issue an additional 15,151,516 shares of new common stock and, immediately following the completion of this offering, we will have 106,431,603 total shares of common stock outstanding, in each case, assuming the underwriters do not exercise their option to purchase additional shares.

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DILUTION

        If you invest in our common stock, your interest will be diluted to the extent of the difference between the initial public offering price per share of our common stock and the pro forma as adjusted net tangible book value per share of our common stock after this offering. We calculate net tangible book value per share by dividing the net tangible book value (tangible assets less total liabilities) by the number of outstanding shares of common stock.

        Our net tangible book value as of September 30, 2017 was approximately $(606.6) million, or $(0.17) per share of common stock, not taking into account our reverse stock split or the recapitalization of our outstanding convertible preferred stock into shares of common stock. Our pro forma net tangible book value as of September 30, 2017 was approximately $(606.6) million, or $(6.65) per share, after giving effect to our 69.196592:1 reverse stock split and the recapitalization of all outstanding shares of our convertible preferred stock into 39,450,826.48 shares of our common stock, in each case, assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. A change in the public offering price would change the number of shares outstanding prior to the completion of this offering by less than 1%. Following the reverse stock split and recapitalization, fractional shares will be paid out in cash.

        After giving effect to the sale of 15,151,516 shares of common stock by us in this offering, assuming an initial public offering price of $16.50 per share, the midpoint of the price range set forth on the cover page of this prospectus, less underwriting discounts and commissions and estimated offering expenses, our pro forma as adjusted net tangible book value as of September 30, 2017 would have been approximately $(382.2) million, or approximately $(3.59) per share. This represents an immediate decrease in the pro forma net tangible book value of $3.41 per share to existing stockholders and an immediate dilution of $20.08 per share to investors purchasing shares in this offering. The following table illustrates this per share dilution:

Assumed initial public offering price per share

        $ 16.50  

Net tangible book value per share as of September 30, 2017

  $ (0.17 )      

Pro forma increase (decrease) in net tangible book value per share attributable to reverse stock split and recapitalization of convertible preferred stock

    (6.48 )      

Pro forma increase per share attributable to this offering

    3.06        

Pro forma as adjusted net tangible book value per share after this offering

          (3.59 )

Dilution per share to new investors in this offering

        $ 20.09  

        If the over-allotment option that we have granted to the underwriters is exercised in full, our pro forma as adjusted net tangible book value as of September 30, 2017 would be $(346.7) million, the increase in the pro forma as adjusted net tangible book value per share to existing stockholders would be $(3.19) per share and the dilution per share to investors purchasing shares in this offering would be $19.69 per share.

        Each $1.00 increase (decrease) in the assumed initial public offering price of $16.50 per share, the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) the pro forma as adjusted net tangible book value per share by $0.14 per share and the dilution per share to new investors by $0.14 per share, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

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        The following table shows, as of September 30, 2017, on a pro forma as adjusted basis as described above, the difference between the number of shares of common stock purchased from us, the total consideration paid to us and the average price per share (1) paid to us by existing stockholders and (2) to be paid by new investors purchasing common stock in this offering at an assumed initial public offering price of $16.50 per share, the midpoint of the price range set forth on the cover page of this prospectus, before deducting underwriting discounts and commissions and estimated offering expenses.

 
   
   
  Total
Consideration
   
 
 
  Shares Purchased    
 
 
  Average Price
per Share
 
 
  Number   Percent   Amount   Percent  

Existing stockholders

    91,280,087     85.8 % $ 2,943,474,570     92.2 % $ 32.25  

New investors

    15,151,516     14.2 %   250,000,014     7.8 %   16.50  

Total

    106,431,603     100.0 % $ 3,193,474,584     100.0 % $ 30.00  

        Each $1.00 increase (decrease) in the assumed initial public offering price of $16.50 per share, the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) total consideration paid by new investors by $14.4 million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting underwriting discounts and commissions and estimated offering expenses.

        If the over-allotment option that we have granted to the underwriters is exercised in full, the percentage of shares held by existing stockholders will decrease to 84.0% and the number of shares held by new investors will increase to 17,424,243, or 16.0%.

        The discussion and tables above exclude shares of common stock reserved for issuance under the 2014 LTIP.

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SELECTED FINANCIAL DATA

        The consolidated statements of operations data for the years ended December 31, 2015 and 2016, and the consolidated balance sheet data as of December 31, 2015 and 2016, are derived from our Audited Consolidated Financial Statements that are included elsewhere in this prospectus. The consolidated statements of operations data for the nine months ended September 30, 2016 and 2017 and the consolidated balance sheet data as of September 30, 2017 are derived from our Unaudited Consolidated Financial Statements that are included elsewhere in this prospectus. The consolidated statements of operations data for the years ended December 31, 2012, 2013, and 2014 and the consolidated balance sheet data as of December 31, 2012, 2013, and 2014 are derived from consolidated financial statements that are not included in this prospectus. The results of operations for the periods presented below are not necessarily indicative of the results to be expected for any future period, and the results for any interim period are not necessarily indicative of the results that may be expected for a full fiscal year.

        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 prospectus.

 
  Year Ended December 31,   Nine Months
Ended September 30,
 
(Dollars in millions, except per share
amounts)

  2012   2013   2014   2015   2016   2016   2017  

Statements of Operations Data:

                                           

Revenue

  $ 1,925.0   $ 1,925.5   $ 2,368.4   $ 1,375.3   $ 532.2   $ 379.8   $ 1,007.4  

Costs of revenue, excluding depreciation, depletion, and amortization(1)

    1,489.5     1,478.4     1,804.9     1,257.9     510.5     369.7     709.9  

Selling, general and administrative

    208.4     189.6     206.3     154.7     64.4     51.5     62.0  

Depreciation, depletion and amortization(2)

    364.5     355.7     294.4     272.4     112.6     87.5     65.2  

Impairments and other charges(3)

    1,534.9     1,147.4     9.8     619.9     12.3     10.7     1.4  

Loss (gain) on disposal of assets, net(4)

    6.1     295.8     5.8     5.9     1.0     1.1     (1.6 )

Gain on insurance recoveries

                    (15.1 )   (15.1 )   (2.9 )

Operating income (loss)

    (1,678.4 )   (1,541.4 )   47.2     (935.5 )   (153.5 )   (125.6 )   173.4  

Interest expense, net

    130.3     129.1     74.2     77.2     87.5     66.1     64.8  

Loss (gain) on extinguishment of debt, net

    7.0     20.3     28.4     0.6     (53.7 )   (53.7 )    

Equity in net loss (income) of joint venture affiliate

                1.4     2.8     2.6     (0.1 )

Income (loss) before income taxes

    (1,815.7 )   (1,690.8 )   (55.4 )   (1,014.7 )   (190.1 )   (140.6 )   108.7  

Income tax expense (benefit)(5)

    0.8     1.5     1.1     (1.5 )   (1.6 )       0.9  

Net income (loss)

  $ (1,816.5 ) $ (1,692.3 ) $ (56.5 ) $ (1,013.2 ) $ (188.5 ) $ (140.6 ) $ 107.8  

Net loss attributable to common stockholders

  $ (1,837.4 ) $ (1,785.1 ) $ (172.4 ) $ (1,158.1 ) $ (370.1 ) $ (272.7 ) $ (56.8 )

Basic and diluted earnings (loss) per share attributable to common stockholders

  $ (0.51 ) $ (0.50 ) $ (0.05 ) $ (0.32 ) $ (0.10 ) $ (0.08 ) $ (0.02 )

Shares used in computing basic and diluted earnings (loss) per share (in millions)

    3,575.1     3,586.3     3,589.6     3,589.7     3,586.5     3,586.5     3,586.4  

Balance Sheet Data (at end of period):

                                           

Cash and cash equivalents

  $ 210.9   $ 80.2   $ 10.5   $ 264.6   $ 160.3         $ 193.8  

Total assets

  $ 3,990.9   $ 1,871.0   $ 1,902.3   $ 907.4   $ 616.8         $ 827.1  

Total debt

  $ 1,549.7   $ 1,076.6   $ 972.5   $ 1,276.2   $ 1,188.7         $ 1,191.6  

Convertible preferred stock(6)

  $ 349.8   $ 349.8   $ 349.8   $ 349.8   $ 349.8         $ 349.8  

Total stockholders' equity (deficit)

  $ 1,926.8   $ 235.8   $ 181.0   $ (830.5 ) $ (1,019.0 )       $ (911.2 )

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  Year Ended December 31,   Nine Months
Ended September 30,
 
(Dollars in millions, except per share
amounts)

  2012   2013   2014   2015   2016   2016   2017  

Pro Forma Data(7):

                                           

Pro forma net income (loss)

                          $ (168.3 )       $ 123.7  

Pro forma basic and diluted earnings (loss) per share attributable to common stockholders

                          $ (1.58 )       $ 1.16  

Pro forma shares used in computing basic and diluted earnings (loss) per share (in millions)(8)

                            106.5           106.5  

Pro forma total debt (at end of period)

                                      $ 847.2  

Pro forma total stockholders' equity (deficit) (at end of period)

                                      $ (342.6 )

Other Data:

                                           

Adjusted EBITDA(9)

  $ 237.5   $ 264.1   $ 359.3   $ (62.8 ) $ (50.8 ) $ (47.7 ) $ 234.2  

Net debt (at end of period)(10)

  $ 1,338.8   $ 996.4   $ 962.0   $ 1,011.6   $ 1,028.4         $ 997.8  

Pro forma net debt (at end of period)(10)

                                      $ 779.0  

Capital expenditure

  $ 149.4   $ 79.4   $ 112.1   $ 79.1   $ 10.3   $ 6.1   $ 33.4  

Total fracturing stages(11)

    17,959     22,977     26,182     21,919     16,185     11,135     22,672  

(1)
The amount of depreciation, depletion and amortization related to our costs of revenue that has been classified as depreciation, depletion and amortization in this table for the year ended December 31, 2012, 2013, 2014, 2015 and 2016 is $226.6 million, $223.7 million, $175.7 million, $152.3 million and $98.9 million, respectively, and for the nine months ended September 30, 2016 and 2017 is $76.9 million and $56.7 million, respectively.

(2)
We recorded depletion of $6.0 million and $4.2 million in 2012 and 2013, respectively, related to our sand mines before selling those assets in the third quarter of 2013.

(3)
In 2012, this amount includes a goodwill impairment of $1,484.9 million and a tradename impairment of $38.9 million. 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 years ended December 31, 2015 and 2016 and for the nine months ended September 30, 2016 and 2017, see Note 10—"Impairments and Other Charges" in Notes to our Audited Consolidated Financial Statements included elsewhere in this prospectus and Note 4—"Impairments and Other Charges" in Notes to our Unaudited Condensed Consolidated Financial Statements included elsewhere in this prospectus.

(4)
In 2013, this amount includes a loss of $289.7 million related to the sale of our sand mining, processing and logistics assets.

(5)
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.

(6)
The holders of the convertible preferred stock are also common stockholders of the Company and collectively appoint 100% of our board of directors. Therefore, the convertible preferred stockholders can direct the Company to redeem the convertible preferred stock at any time after all of our debt has 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 7—"Convertible Preferred Stock" in Notes to our Audited Consolidated Financial Statements included elsewhere in this prospectus for more information. At September 30, 2017, the liquidation preference of the convertible preferred stock was estimated to be $1,070.7 million.

(7)
Pro forma data gives effect to (1) the 69.196592:1 reverse stock split, (2) the recapitalization of our convertible preferred stock into 39,450,826.48 shares of common stock, (3) the sale of 15,151,516 shares of common stock to be issued by us in this offering (assuming the underwriters do not exercise their option to purchase additional shares) and (4) the use of proceeds therefrom, as if each of these events occurred on January 1, 2016 for purposes of the statement of operations and September 30, 2017, for purposes of the balance sheet, and for each of (1), (2), (3) and (4), assuming an initial public offering price of $16.50 per share, the midpoint of the range set forth on the cover page of this prospectus. Additionally, the pro forma balance sheet information reflects a share-based compensation expense of approximately $3.7 million associated with restricted stock units issued under our 2014 LTIP that will vest immediately before effectiveness of the registration statement, of which this prospectus is a part, and will be settled in cash. A change in the public offering price would change the number of shares outstanding prior to the

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    completion of this offering by less than 1%. For additional information regarding the recapitalization of our convertible preferred stock, see "Description of Capital Stock."

(8)
The pro forma shares used to compute pro forma earnings per share for the year ended December 31, 2016, and the nine months ended September 30, 2017, have been adjusted to include the sale of 15,151,516 shares of common stock in this offering that would generate only enough proceeds to repay debt as described under "Use of Proceeds."

(9)
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,   Nine Months
Ended
September 30,
 
(In millions)
  2012   2013   2014   2015   2016   2016   2017  

Net income (loss)

  $ (1,816.5 ) $ (1,692.3 ) $ (56.5 ) $ (1,013.2 ) $ (188.5 ) $ (140.6 ) $ 107.8  

Interest expense, net

    130.3     129.1     74.2     77.2     87.5     66.1     64.8  

Income tax expense (benefit)

    0.8     1.5     1.1     (1.5 )   (1.6 )       0.9  

Depreciation, depletion and amortization

    364.5     355.7     294.4     272.4     112.6     87.5     65.2  

Loss (gain) on disposal of assets, net

    6.1     295.8     5.8     5.9     1.0     1.1     (1.6 )

Loss (gain) on extinguishment of debt, net

    7.0     20.3     28.4     0.6     (53.7 )   (53.7 )    

Inventory write-down

                24.5              

Impairment of assets and goodwill

    1,533.9     1,145.2     9.8     572.9     7.0     7.0      

Gain on insurance recoveries

                    (15.1 )   (15.1 )   (2.9 )

Acquisition earn-out adjustments

                (3.4 )            

Stock-based compensation

    1.4     1.6     2.1     1.8              

Transaction costs(a)

    10.0     7.2                      

Adjusted EBITDA

  $ 237.5   $ 264.1   $ 359.3   $ (62.8) (b) $ (50.8) (c) $ (47.7) (d) $ 234.2 (e)

(a)
In 2012, these costs related to a debt refinancing transaction that was not consummated and a loss on an uncollected receivable that was related to a change of control event in 2011. In 2013, these costs related to the sale of our proppant assets.

(b)
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.

(c)
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.

(d)
For the nine months ended September 30, 2016, Adjusted EBITDA has not been adjusted to exclude the following items: employee severance costs of $0.8 million, supply commitment charges of $1.5 million and lease abandonment charges of $1.4 million.

(e)
For the nine months ended September 30, 2017, Adjusted EBITDA has not been adjusted to exclude a supply commitment charge of $1.0 million.
(10)
Net debt is a non-GAAP financial measure that we define as total debt less cash and cash equivalents. The most comparable financial measure to net debt under GAAP is debt. Net debt is used by management as a measure of our financial leverage. Net debt should not be used by investors or others as the sole basis in formulating investment

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    decisions as it does not represent our actual indebtedness. Pro forma net debt is net debt adjusted as if we received the net proceeds from this offering and we (a) settled the restricted stock units granted under the 2014 LTIP in cash and (b) redeemed $350.0 million of our outstanding 2020 Notes as if each of these events occurred on September 30, 2017.

    The following table reconciles our total debt to net debt:

 
  As of December 31,   As of
September 30,
 
(In millions)
  2012   2013   2014   2015   2016   2017  

Total debt

  $ 1,549.7   $ 1,076.6   $ 972.5   $ 1,276.2   $ 1,188.7   $ 1,191.6  

Cash and cash equivalents

    (210.9 )   (80.2 )   (10.5 )   (264.6 )   (160.3 )   (193.8 )

Net debt

  $ 1,338.8   $ 996.4   $ 962.0   $ 1,011.6   $ 1,028.4   $ 997.8  

    The following table reconciles our total debt to pro forma net debt:

(In millions)
  As of
September 30. 2017
 

Total debt

  $ 1,191.6  

Repayment of 2020 Notes

    (344.4 )

Pro forma total debt

    847.2  

Cash and cash equivalents

    193.8  

Net proceeds from this offering

    233.4  

Cash settlement of 2014 restricted stock units

    (3.7 )

Cash paid to repurchase 2020 Notes

    (355.3 )

Pro forma cash and cash equivalents

    68.2  

Pro forma net debt

  $ 779.0  
(11)
See "Business—Our Services—Hydraulic Fracturing" regarding fracturing stages and the types of service agreements we use to provide hydraulic fracturing services.

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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 prospectus. 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 prospectus, 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. We manufacture and assemble many of the components of our hydraulic fracturing fleets, including all of the hydraulic pumps and consumables, such as fluid ends, we use in our operations. We also perform substantially all refurbishment, repair and maintenance services on our hydraulic fracturing fleets.

    Significant developments in 2016 and the first nine months of 2017

    In February 2016, we sold substantially all of our remaining sand transportation equipment and related inventory for $8.0 million and began to take advantage of low pricing and sand transportation innovations by utilizing third-party freight providers to transport sand to our job sites.

    Our joint venture, SinoFTS Petroleum Services Ltd., or SinoFTS, completed its first hydraulic fracturing jobs in Chongqing, China in 2016 and continues to expand its presence in the Chinese market.

    In July 2016, we completed a tender offer and subsequent purchases in the qualified institutional buyer/144A market for a portion of our long-term debt in which we repurchased approximately $90.7 million of aggregate principal amount of long-term debt and recorded a gain on debt extinguishment of $52.3 million.

    During the first quarter of 2017, we reached a milestone of over 10 million man-hours without a lost time incident, that 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 the first nine months of 2017, we generated positive operating income for the first time since 2014 and positive net income for the first time since 2011.

    During the first nine months of 2017, we activated nine fleets in response to increased customer demand, which brought our total active fleet count to 26 at September 30, 2017.

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    Trends that affected our business in 2016 and the first nine months of 2017

        Our business 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 is predominantly influenced by current and expected prices for oil and natural gas.

        In early 2016, we experienced the lowest commodity prices in over a decade; however, oil and natural gas prices started improving in the second quarter of the year 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 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.

        Higher commodity prices enabled our customers to significantly increase their activity levels in the first nine months of 2017, which resulted in an increase in the horizontal rig count from 532 at the end of 2016 to 794 at September 29, 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 additional 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 an opportunity to activate additional fleets at favorable operating margins. Our 28th fleet is scheduled to be activated at the end of January 2018. We are also focused on minimizing cost inflation in this environment to optimize our operating margins.

Results of Operations

Three and Nine Months Ended September 30, 2017 Compared to Three and Nine Months Ended September 30, 2016

    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" for details regarding fracturing stages and fleets and

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the types of agreements we use to provide hydraulic fracturing services. The following table includes certain operating statistics that affect our revenue:

 
  Three Months
Ended
September 30,
  Nine Months
Ended
September 30,
 
(Dollars in millions)
  2016   2017   2016   2017  

Revenue

  $ 123.8   $ 409.8   $ 377.1   $ 906.1  

Revenue from related parties

    1.6     39.2     2.7     101.3  

Total revenue

  $ 125.4   $ 449.0   $ 379.8   $ 1,007.4  

Total fracturing stages

    4,367     8,196     11,135     22,672  

Active fleets(1)

    15.7     24.8     15.1     22.4  

Total fleets(2)

    32.0     32.0     32.0     32.0  

(1)
Active fleets is the average number of fleets operating during the period. As of December 31, 2016 and September 30, 2017, we had 17 and 26 active fleets, respectively.

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

        Total revenue for the third quarter and first nine months of 2017 increased by $323.6 million and $627.6 million, respectively, from the same periods in 2016. These increases in revenue were 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 the third quarter and first nine months of 2017 increased by 9.1 and 7.3, respectively, from the same periods in 2016, due to increased customer demand. At September 30, 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 nine months, if market conditions require. We estimated the total cost to reactivate all of our inactive fleets, as of September 30, 2017, would be approximately $29 million, including capital expenditures, repairs charged as operating expense, labor costs, and other operating expenses. As of December 31, 2017, we estimated the total cost to reactivate all of our inactive fleets would be approximately $34.0 million, including capital expenditures, repairs charged as operating expense, labor costs, and other operating expenses.

        The increase in revenue from related parties in the third quarter and first nine months of 2017 were due to increases in the activity levels for Chesapeake Parent.

    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

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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:

 
  Three Months Ended September 30,  
 
  2016   2017  
(Dollars in millions)
  Dollars   As a Percent
of Revenue
  Dollars   As a Percent
of Revenue
 

Costs of revenue, excluding depreciation

  $ 125.7     100.2 % $ 298.8     66.6 %

Depreciation—costs of revenue

    24.9     19.9 %   19.4     4.3 %

Total costs of revenue

  $ 150.6     120.1 % $ 318.2     70.9 %

 

 
  Nine Months Ended September 30,  
 
  2016   2017  
(Dollars in millions)
  Dollars   As a Percent
of Revenue
  Dollars   As a Percent
of Revenue
 

Costs of revenue, excluding depreciation

  $ 369.7     97.4 % $ 709.9     70.5 %

Depreciation—costs of revenue

    76.9     20.2 %   56.7     5.6 %

Total costs of revenue

  $ 446.6     117.6 % $ 766.6     76.1 %

        Total costs of revenue for the third quarter and first nine months of 2017 increased by $167.6 million and $320.0 million, respectively, from the same periods in 2016. These increases were primarily due to increases in our costs of revenue, excluding depreciation, which were partially offset by decreases in the depreciation expense for our service equipment.

        Costs of revenue, excluding depreciation, for the third quarter and first nine months of 2017 increased by $173.1 million and $340.2 million, respectively, from the same periods in 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 the third quarter and first nine months of 2017 decreased by $5.5 million and $20.2 million, respectively, from the same periods in 2016. These decreases were 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 for the third quarter decreased by 49.2 percentage points from 120.1% in 2016 to 70.9% in 2017. Total costs of revenue as a percentage of total revenue for the first nine months of 2017 decreased by 41.5 percentage points from 117.6% in 2016 to 76.1% in 2017. These changes were 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.

    Selling, general and administrative expense

        Selling, general and administrative expense in the third quarter and first nine months of 2017 increased by $5.9 million and $10.5 million from the same periods in 2016. These increases were 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. The factors that contributed to the increase in selling, general and administrative expense for the first nine months of 2017 were partially offset by a lower corporate employee headcount in the first quarter of 2017, when compared to the first quarter 2016.

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    Depreciation and amortization

        The following table summarizes our depreciation and amortization:

 
  Three Months
Ended
September 30,
  Nine Months
Ended
September 30,
 
(In millions)
  2016   2017   2016   2017  

Depreciation—costs of revenue(1)

  $ 24.9   $ 19.4   $ 76.9   $ 56.7  

Depreciation—other(2)

    3.4     2.7     10.6     8.5  

Total depreciation and amortization

  $ 28.3   $ 22.1   $ 87.5   $ 65.2  

(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 assets other than service equipment included in "Property, plant, and equipment, net" on our consolidated balance sheets.

        Depreciation and amortization in the third quarter and first nine months of 2017 decreased by $6.2 million and $22.3 million from the same periods in 2016. These decreases were primarily due to decreases in depreciation for our service equipment, which has been previously discussed. The remaining decreases were primarily due to asset disposals and certain assets becoming fully depreciated.

    Impairments and other charges

        The following table summarizes our impairments and other charges:

 
  Three Months
Ended
September 30,
  Nine Months
Ended
September 30,
 
(In millions)
  2016   2017   2016   2017  

Impairment of assets

  $ 4.4   $   $ 7.0   $  

Supply commitment charges

            1.5     1.0  

Lease abandonment charges

    0.8     0.1     1.4     0.4  

Employee severance costs

            0.8      

Total impairments and other charges

  $ 5.2   $ 0.1   $ 10.7   $ 1.4  

        Impairments and other charges include supply commitment charges related to contractual inventory purchase commitments to certain proppant suppliers. During the second quarter of 2016 and 2017, we recorded charges under these supply arrangements of $1.5 million and $1.0 million, respectively. The 2016 charge was attributable to our decreased volume of purchases from these suppliers due to our lower activity levels and certain customers procuring their own proppants. The 2017 charge was due to our customer requirements not satisfying our contracted commitments for certain proppants. For additional information, see "Critical Accounting Policies and Estimates—Unconditional Purchase Obligations."

        We recorded asset impairments of $7.0 million in the first nine months of 2016 related to certain property that we no longer use and had identified to sell.

        During 2015 and 2016, we vacated certain leased facilities to consolidate our operations. During the first nine months of 2016 and 2017, we recognized expense of $1.4 million and $0.4 million, respectively, in connection with these actions.

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        We incurred employee severance costs of $0.8 million in the first quarter of 2016. These costs were incurred in connection with our corporate and operating restructuring initiatives. As of December 31, 2016, we had paid all severance payments owed to former employees.

    Loss (gain) on disposal of assets, net

        We sold substantially all of our sand transportation equipment and related inventory in February 2016. We received $8.0 million of proceeds and recognized a $0.3 million gain on this sale. In the first nine months of 2016 and 2017, we sold a number of other surplus pieces of equipment. In the first nine months of 2016, we received $18.3 million of proceeds and recognized a $1.4 million net loss on the sale of these assets. In the first nine months of 2017, we received $2.0 million of proceeds and recognized a $1.6 million net gain on the sale of these assets.

    Gain on insurance recoveries

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

        In January 2017, a fire destroyed certain equipment in one of our fleets. These assets were insured at values greater than their carrying values. We received $4.2 million of insurance recovery proceeds for these assets, which exceeded their carrying values by $2.9 million.

    Interest expense, net

        Interest expense, net of interest income, increased by $0.7 million in the third quarter of 2017 from the same period in 2016. This increase was primarily due to higher average interest rates for our 2020 Notes in 2017.

        Interest expense, net of interest income, decreased by $1.3 million in the first nine months of 2017 from the same period in 2016. This decrease was primarily due to a lower average long-term debt balance, which was partially offset by higher average interest rates for our 2020 Notes in 2017.

    Gain on extinguishment of debt

        In the third quarter of 2016, we completed a tender offer and subsequent purchases in the qualified institutional buyer/144A 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 $0.4 million in the third quarter of 2017 and $0.9 million in the nine months ended September 30, 2017. These amounts 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 for the nine months ended September 30, 2016 and 2017.

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Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

    Revenue

        The following table includes certain operating statistics that affect our revenue:

 
  Year Ended
December 31,
 
(Dollars in millions)
  2015   2016  

Revenue

  $ 1,331.8   $ 529.5  

Revenue from related parties

    43.5     2.7  

Total revenue

  $ 1,375.3   $ 532.2  

Total fracturing stages

    21,919     16,185  

Active fleets(1)

    23.0     15.6  

Total fleets(2)

    33.0     32.0  

(1)
Active fleets is the average number of fleets operating during the period.

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

        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, 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 Parent.

    Costs of revenue

        Costs of revenue as a percentage of total revenue is as follows:

 
  Year Ended December 31,  
 
  2015   2016  
(Dollars in millions)
  Dollars   As a Percent
of Revenue
  Dollars   As a Percent
of Revenue
 

Costs of revenue, excluding depreciation

  $ 1,257.9     91.5 % $ 510.5     95.9 %

Depreciation—costs of revenue

    152.3     11.1 %   98.9     18.6 %

Total costs of revenue

  $ 1,410.2     102.5 % $ 609.4     114.5 %

        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.

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        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 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 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)
  2015   2016  

Depreciation—costs of revenue(1)

  $ 152.3   $ 98.9  

Depreciation—other(2)

    17.6     13.7  

Amortization(3)

    102.5      

Total depreciation and amortization

  $ 272.4   $ 112.6  

(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 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.

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    Impairments and other charges

        The following table summarizes our impairments and other charges:

 
  Year Ended
December 31,
 
(In millions)
  2015   2016  

Impairment of assets and goodwill

  $ 572.9   $ 7.0  

Supply commitment charges

    11.0     2.5  

Lease abandonment charges

    1.8     2.0  

Employee severance costs

    13.1     0.8  

Inventory write-down

    24.5      

Acquisition earn-out adjustments

    (3.4 )    

Total impairments and other charges

  $ 619.9   $ 12.3  

        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.

        Supply Commitment Charges:    We have recorded supply commitment charges related to contractual inventory purchase commitments to certain proppant suppliers. In 2015 and 2016, we recorded charges under these supply arrangements of $11.0 million and $2.5 million, respectively. These charges were attributable to our decreased volume of purchases from these suppliers due to our lower activity levels in both periods. Additionally, in 2016, our decreased purchases were also due to certain customers procuring their own proppants.

        Lease Abandonment Charges:    During 2015 and 2016, we vacated certain leased facilities to consolidate our operations. In 2015 and 2016, we recognized expense of $1.8 million and $2.0 million, respectively, in connection with these actions.

        Employee Severance Costs:    During 2015 and 2016, we incurred employee severance costs of $13.1 million and $0.8 million, respectively, in connection with our corporate and operating

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restructuring initiatives. At December 31, 2015 and 2016, we had paid substantially all severance payments owed to former employees.

        Inventory Write-down:    During 2015, we made improvements to our supply chain that reduced our inventory requirements. In connection with this initiative, we executed a program to liquidate excess inventory. We recorded a $24.5 million inventory write-down charge in connection with this liquidation program.

        Acquisition Earn-Out Adjustments:    In the second quarter and fourth quarter of 2015, we remeasured the fair value of the contingent consideration related to our wireline acquisition and we recorded adjustments to reduce this liability by $3.0 million and $0.4 million, respectively. At December 31, 2015 and December 31, 2016, the fair value of the contingent consideration was zero and the period to earn the contingent consideration expired on October 31, 2016.

    Loss on disposal of assets, net

        We sold substantially all of our remaining sand transportation equipment and related inventory in February 2016. We received $8.0 million of proceeds and recognized a $0.3 million gain on this sale. During 2016, we sold a number of other surplus pieces of property and equipment. We received an additional $23.5 million of proceeds and recognized a $1.3 million net loss on the sale of these assets.

    Gain on insurance recoveries

        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 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 for our 2020 Notes in 2016.

    Gain on extinguishment of debt, net

        In the third quarter of 2016, we completed a tender offer and subsequent purchases in the qualified institutional buyer/144A 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. See Note 6—"Debt" in Notes to our Audited Consolidated Financial Statements included elsewhere in this prospectus for more information.

    Income tax expense

        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 benefit related to our losses in 2016 or 2015. See Note 13—"Income Taxes" in Notes to our Audited Consolidated Financial Statements included elsewhere in this prospectus for more information regarding our income taxes and valuation allowance.

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    Selected Quarterly Financial Information

        To provide additional financial information relative to recent quarterly results of the Company, the following table presents selected unaudited quarterly financial information for the year ended December 31, 2016 and the nine months ended September 30, 2017:

 
  Quarter Ended  
(Dollars in millions)
  Mar. 31,
2016
  Jun. 30,
2016
  Sep. 30,
2016
  Dec. 31,
2016
  Mar. 31,
2017
  Jun. 30,
2017
  Sep. 30,
2017
 

Statements of Operations Data:

                                           

Revenue

  $ 148.7   $ 105.7   $ 125.4   $ 152.4   $ 213.5   $ 344.9   $ 449.0  

Costs of revenue, excluding depreciation and amortization

    141.2     102.8     125.7     140.8     174.8     236.3     298.8  

Selling, general and administrative

    20.2     15.5     15.8     12.9     19.5     20.8     21.7  

Depreciation and amortization

    30.1     29.1     28.3     25.1     21.8     21.3     22.1  

Impairments and other charges

    1.6     3.9     5.2     1.6     0.1     1.2     0.1  

Loss (gain) on disposal of assets, net

    2.8     (1.7 )       (0.1 )   (0.4 )   (0.4 )   (0.8 )

Gain on insurance recoveries

    (12.5 )   (2.6 )           (2.6 )   (0.3 )    

Operating (loss) income

    (34.7 )   (41.3 )   (49.6 )   (27.9 )   0.3     66.0     107.1  

Interest expense, net

    (22.3 )   (22.4 )   (21.4 )   (21.4 )   (21.2 )   (21.5 )   (22.1 )

Gain on extinguishment of debt, net

        1.4     52.3                  

Equity in net (loss) income of joint venture affiliate

    (1.0 )   (0.9 )   (0.7 )   (0.2 )   0.9     0.2     (1.0 )

(Loss) income before income taxes

    (58.0 )   (63.2 )   (19.4 )   (49.5 )   (20.0 )   44.7     84.0  

Income tax (benefit) expense

                (1.6 )   0.1     0.4     0.4  

Net (loss) income

  $ (58.0 ) $ (63.2 ) $ (19.4 ) $ (47.9 ) $ (20.1 ) $ 44.3     83.6  

Balance Sheet Data (end of period):

                                           

Cash and cash equivalents

  $ 280.9   $ 264.8   $ 195.0   $ 160.3   $ 126.7   $ 138.5   $ 193.8  

Total debt

  $ 1,277.1   $ 1,276.1   $ 1,187.7   $ 1,188.7   $ 1,189.6   $ 1,190.6   $ 1,191.6  

Other Data:

   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

Adjusted EBITDA

  $ (14.7 ) $ (15.4 ) $ (17.6 ) $ (3.1 ) $ 20.0   $ 86.8   $ 127.4  

Total fracturing stages

    3,273     3,495     4,367     5,050     6,523     7,953     8,196  

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

 
  Quarter Ended  
(In millions)
  Mar. 31,
2016
  Jun. 30,
2016
  Sep. 30,
2016
  Dec. 31,
2016
  Mar. 31,
2017
  Jun. 30,
2017
  Sep. 30,
2017
 

Net (loss) income

  $ (58.0 ) $ (63.2 ) $ (19.4 ) $ (47.9 ) $ (20.1 ) $ 44.3   $ 83.6  

Interest expense, net

    22.3     22.4     21.4     21.4     21.2     21.5     22.1  

Income tax (benefit) expense

                (1.6 )   0.1     0.4     0.4  

Depreciation and amortization

    30.1     29.1     28.3     25.1     21.8     21.3     22.1  

Loss (gain) on disposal of assets, net

    2.8     (1.7 )       (0.1 )   (0.4 )   (0.4 )   (0.8 )

Gain on extinguishment of debt, net

        (1.4 )   (52.3 )                

Impairment of assets and goodwill

    0.6     2.0     4.4                  

Gain on insurance recoveries

    (12.5 )   (2.6 )           (2.6 )   (0.3 )    

Adjusted EBITDA

  $ (14.7 ) $ (15.4 ) $ (17.6 ) $ (3.1 ) $ 20.0   $ 86.8   $ 127.4  

Liquidity and Capital Resources

    Sources of Liquidity

        At September 30, 2017, we had $193.8 million of cash, which represented our total liquidity position. We believe that our cash and any cash provided by operations will be sufficient to fund our operations and capital expenditures for at least the next 12 months.

    Cash Flows for the Nine Months Ended September 30, 2016 and 2017

        The following table summarizes our cash flows:

 
  Nine Months Ended
September 30,
 
(In millions)
  2016   2017  

Net (loss) income adjusted for non-cash items

  $ (106.9 ) $ 171.8  

Changes in operating assets and liabilities

    32.8     (111.5 )

Net cash (used in) provided by operating activities

    (74.1 )   60.3  

Net cash provided by (used in) investing activities

    42.1     (26.8 )

Net cash used in financing activities

    (37.6 )    

Net (decrease) increase in cash

    (69.6 )   33.5  

Cash, beginning of period

    264.6     160.3  

Cash, end of period

  $ 195.0   $ 193.8  

        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.

        Net cash used in operating activities was $74.1 million for the first nine months of 2016 compared to net cash provided by operating activities of $60.3 million in the same period in 2017. 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 decrease of $106.9 million and a cash increase of $171.8 million for the first nine months of 2016 and 2017, respectively. This increase was primarily due to higher earnings in 2017. The net change in operating assets and liabilities resulted in a cash increase of $32.8 million and a cash decrease of $111.5 million for the first nine months of 2016 and 2017, respectively. The net change in operating

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assets and liabilities for the first nine months of 2017 was primarily due to an increase in working capital resulting from our increased activity level.

        Net cash provided by investing activities was $42.1 million for the first nine months of 2016 compared to cash used in investing activities of $26.8 million for the first nine months of 2017. 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.

        Net cash used in financing activities for the first nine months of 2016 was $37.6 million, which was comprised of debt repurchases.

    Cash Flows for the Years Ended December 31, 2015 and 2016

        The following table summarizes our cash flows:

 
  Year Ended
December 31,
 
(In millions)
  2015   2016  

Net loss adjusted for non-cash items

  $ (133.3 ) $ (130.9 )

Changes in operating assets and liabilities

    183.9     21.1  

Net cash provided by (used in) operating activities

    50.6     (109.8 )

Net cash (used in) provided by investing activities

    (97.9 )   43.1  

Net cash provided by (used in) financing activities

    301.4     (37.6 )

Net increase (decrease) in cash

    254.1     (104.3 )

Cash, beginning of period

    10.5     264.6  

Cash, end of period

  $ 264.6   $ 160.3  

        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.

        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. Cash flows from operating activities consists of net loss adjusted for non-cash items and changes in operating assets and liabilities. Net loss adjusted for non-cash items resulted in a cash decrease of $133.3 million and $130.9 million in 2015 and 2016, respectively. The net change in operating assets and liabilities resulted in a cash increase of $183.9 million and $21.1 million in 2015 and 2016, 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.

        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.

        Net cash used in financing activities in 2016 was $37.6 million compared to net cash provided by financing activities of $301.4 million in 2015. The net decrease in cash flows in 2016 was due to debt repurchases. The net increase in cash flows in 2015 was due to the issuance of $350 million aggregate principal amount of our 2020 Notes, partially offset by a repayment of borrowings under our previously existing revolving credit facility.

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Cash Requirements

    Contractual Commitments and Obligations

        The following table summarizes our contractual commitments at December 31, 2016 and does not give effect to the use of proceeds from this offering:

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

Long-term debt obligations

  $ 1,207.3   $   $   $ 781.0   $ 426.3  

Interest obligations(1)(2)

    359.8     82.0     163.6     100.9     13.3  

Operating lease obligations

    38.8     20.8     13.0     4.3