10-K 1 cjes1231201810-kdoc.htm 10-K Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549 
FORM 10-K 
(Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2018
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM                      TO                     
Commission File Number: 000-55404
 
C&J Energy Services, Inc.
(Exact name of registrant as specified in its charter)
 
 
Delaware
 
81-4808566
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
3990 Rogerdale Rd.
Houston, Texas 77042
(Address of principal executive offices)
(713) 325-6000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of exchange on which registered
 
 
 
Common stock, Par value $0.01 per share
 
The New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: Warrants, each exercisable to purchase one share of Common Stock, $0.01 par value per share  
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ý   No  ¨
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ý
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act
Large accelerated filer
 
ý

  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
¨
  
Smaller reporting company
 
¨
 
 
 
 
 
 
 
Emerging growth 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 13(a) of the Exchange Act.  ¨
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No    ý



Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ý No ¨

The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2018 (the last business day of the registrant’s most recently completed second fiscal quarter) based upon the closing price on the New York Stock Exchange on that date was approximately $1.4 billion.
The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at February 22, 2019, was 66,062,430.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for its 2019 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2018, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 



TABLE OF CONTENTS
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




PART I
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (this “Annual Report”) includes certain statements and information that may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “plan,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “will,” “could,” “should,” “potential,” “would,” “may,” “probable,” “likely,” and similar expressions that convey the uncertainty of future events or outcomes, and the negative thereof, are intended to identify forward-looking statements. Forward-looking statements, which are not generally historical in nature, include those that express a belief, expectation or intention regarding our future activities, plans and goals and our current expectations with respect to, among other things, our business strategy and our financial strategy.
Forward-looking statements are not assurances of future performance and actual results could differ materially from our historical experience and our present expectations or projections. These forward-looking statements are based on management’s current expectations and beliefs, forecasts for our existing operations, experience, expectations and perception of historical trends, current conditions, anticipated future developments and their effect on us, and other factors believed to be appropriate. Although management believes the expectations and assumptions reflected in these forward-looking statements are reasonable as and when made, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all). Our forward-looking statements involve significant risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Known material factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, risks associated with the following:
a decline in demand for our services, including due to supply of oil and gas, declining or perceived instability of commodity prices, overcapacity of supply, constrained pipeline capacity and other competitive factors affecting our industry;
the cyclical nature and volatility of the oil and gas industry, which impacts the level of drilling, completion and production activity and spending patterns by our customers;
a decline in, or substantial volatility of, crude oil and gas commodity prices, which generally leads to decreased spending by our customers and negatively impacts drilling, completion and production activity;
pressure on pricing for our services, including due to competition and industry and/or economic conditions, which may impact, among other things, our ability to implement price increases or maintain pricing and margin on our services;
the loss of, or interruption or delay in operations by, one or more of our significant customers;
the failure by one or more of our significant customers to pay amounts when due, or at all;
changes in customer requirements in the markets we serve;
costs, delays, compliance requirements and other difficulties in executing our short and long-term business plans and growth strategies;
the effects of recent or future acquisitions on our business, including our ability to successfully integrate our operations and the costs incurred in doing so and the costs and potential liabilities associated with new or expanded areas of operational risks (such as offshore or international operations);
business growth outpacing the capabilities of our infrastructure;
the loss of, or interruption or delay in operations by, one or more of our key suppliers, including resulting from product defects, recalls or suspensions;
adverse weather conditions in oil or gas producing regions;

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operating hazards inherent in our industry, including the possibility of accidents resulting in personal injury or death, property damage or environmental damage;
the effect of environmental and other governmental regulations on our operations, including the risk that future changes in the regulation of hydraulic fracturing could reduce or eliminate demand for our hydraulic fracturing services;
the incurrence of significant costs and liabilities resulting from litigation or governmental proceedings;
the incurrence of significant costs and liabilities or severe restrictions on our operations or the inability to perform certain operations or provide certain services resulting from a failure to comply, or our compliance with, new or existing regulations;
the effect of new or existing regulations, industry and/or commercial conditions on the availability of and costs for raw materials, consumables and equipment;
the loss of, or inability to attract, key management and other competent personnel;
a shortage of qualified workers;
our ability to implement new technologies and services;
damage to or malfunction of equipment;
our ability to maintain sufficient liquidity and/or obtain adequate financing to allow us to execute our business plan; and
our ability to comply with covenants under our debt facilities.
For additional information regarding known material factors that could affect our operating results and performance, please read (1) “Risk Factors” in Part I, Item 1A and (2) “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Annual Report. Should one or more of these known material risks occur, or should the underlying assumptions prove incorrect, our actual results, performance, achievements or plans could differ materially from those expressed or implied in any forward-looking statement.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise, except as required by law.

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Item 1. Business
Corporate History
C&J Energy Services, Inc., a Delaware corporation (the “Successor” and together with its consolidated subsidiaries for periods subsequent to the Plan Effective Date (as defined below), “C&J” the “Company,” “we,” “us” or “our”) is a leading provider of well construction, intervention, completion, support and other complementary oilfield services and technologies. We provide our services to oil and gas exploration and production companies throughout the continental United States. We are a new well focused provider offering a diverse suite of services throughout the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, rig services, fluids management and other completion and well support services. We are headquartered in Houston, Texas and operate across all active onshore basins in the continental United States.
We were founded in Texas in 1997 as a partnership and converted to a Delaware corporation (“Old C&J”) in connection with our initial public offering, which was completed in 2011 with a listing on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” From 2011 through mid-2015, we significantly invested in a number of strategic initiatives to grow our business, including through service line diversification, vertical integration, technological advancement and geographic expansion, including internationally. In 2015, Old C&J combined with the completion and production services business (the “C&P Business”) of Nabors Industries Ltd. (“Nabors”) in a transformative transaction (the “Nabors Merger”) that significantly expanded the Company’s Completion Services and Well Construction and Intervention Services businesses and added the Well Support Services division to the Company’s service offering. Upon the closing of the Nabors Merger, Old C&J became a subsidiary of C&J Energy Services Ltd., a Bermuda corporation (the “Predecessor” and together with its consolidated subsidiaries for periods prior to the Plan Effective Date, the “Predecessor Companies”).
Due to a severe industry downturn, in July 2016, the Predecessor Companies voluntarily filed petitions for reorganization seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division, with ancillary recognition proceedings filed in Canada and Bermuda (collectively, the “Chapter 11 Proceeding”).
The plan of reorganization (the “Restructuring Plan”) of the Predecessor Companies was confirmed in December 2016, and on January 6, 2017 (the “Plan Effective Date”), the Predecessor Companies substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. Pursuant to the Restructuring Plan, effective on the Plan Effective Date, the Predecessor’s equity was canceled, the Predecessor transferred all of its assets and operations to the Successor and the Predecessor was subsequently dissolved. The Predecessor’s common stock was ultimately delisted from the NYSE. On April 12, 2017, the Successor completed an underwritten public offering of common stock and its common stock began trading again on the NYSE under the symbol “CJ.”
Upon emergence from the Chapter 11 Proceeding, we adopted fresh start accounting ("Fresh Start"). For more information regarding the Chapter 11 Proceeding and adoption of Fresh Start accounting, see Note 14 - Chapter 11 Proceeding and Emergence and Note 15 - Fresh Start Accounting in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K (this “Annual Report”).
The Successor is the successor issuer to the Predecessor for purposes of and pursuant to Rule 12g-3 of the Exchange Act.  Accordingly, references to “C&J,” the “Company,” “we,” “us” or “our” in this Annual Report are to the Successor, together with our consolidated subsidiaries when referring to periods following the Plan Effective Date, and to the Predecessor Companies when referring to periods prior to the Plan Effective Date.
Our principal executive offices are located at 3990 Rogerdale Road, Houston, Texas 77042 and our main telephone number at that address is (713) 325-6000. Our website is available at www.cjenergy.com. We file annual, quarterly and current reports and other documents with the U.S. Securities and Exchange Commission (“SEC”) under the Exchange Act. The SEC maintains an internet site at www.sec.gov that contains reports, proxy and information statements, reports and other information that we and other issuers file electronically with the SEC. We also make available free of charge through our website all reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act, including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statement on Schedule 14A and all amendments to those reports, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Information contained on or available through our website is not a part of or incorporated into this Annual Report or any other report that we may file with or furnish to the SEC.

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Business Overview

From late 2011 through mid-2016, we executed an aggressive growth strategy that diversified the Company’s service offerings and geographic reach (including in such locations as the Middle East, the Americas, and Europe). With the change in our executive team and subsequent Chapter 11 Proceeding in 2016, we refocused our strategy and plans. Beginning in 2016 and into 2018, we divested our non-core businesses, including specialty chemicals, equipment manufacturing, directional drilling and artificial lift. Additionally, we shut down our emergent Middle East operations in 2016 (completing the liquidation in 2018), and sold our Canadian rig business in November 2017, in furtherance of our goal of becoming the leading oilfield services provider across our service offering in onshore basins in the continental United States.

In November 2017, we acquired O-Tex Holdings, Inc., a Texas corporation ("O-Tex"), for approximately $271.9 million, making us one of the largest oilfield cementers in the continental United States. In connection with this transaction, we also acquired the remaining 49.0% non-controlling interest in a partially owned O-Tex subsidiary for $1.25 million, which strengthened the data controls instrument business of our research and technology efforts (collectively, the "O-Tex Transaction"). O-Tex specialized in both primary and secondary downhole specialty cementing services in most major U.S. shale plays. The O-Tex Transaction strengthened our position as a leading oilfield services provider with a best-in-class well construction, intervention and completions platform.
In 2018, we focused on the continuous improvement of our organization, including advancing several ongoing initiatives purposed to strengthen our organization, optimize our business processes, ensure the quality of our operations, and gain greater efficiency over time. We also took a deliberate approach to increasing our core capabilities, adding capacity, growing our core service lines, and fully integrating the O-Tex asset base.
Our Reportable Segments and Strategy
During the first quarter of 2018, we revised our reportable segments. This revision eliminated the Other Services segment, which consisted of those smaller, non-core business lines that have since been divested, including our specialty chemical business, equipment manufacturing and repair business, and coiled tubing operations in the Middle East.  In line with the discontinuance of these business lines, subsequent to the year ended December 31, 2016, financial information for the Other Services reportable segment is only presented for the corresponding prior year period. As a result of the revised reportable segment structure, we have restated the corresponding items of the segment information for all periods presented. As of December 31, 2018, our reportable segments were:
Completion Services, which consists of the following business lines: (1) fracturing services; (2) cased-hole wireline and pumping services; and (3) completion support services, which includes our research and technology (“R&T”) department.
Well Construction and Intervention Services ("WC&I"), which consists of the following business lines: (1) cementing services and (2) coiled tubing services.
Well Support Services, which consists of the following business lines: (1) rig services; (2) fluids management services; and (3) specialty well site services.
During the first quarter of 2018, we decided to exit our directional drilling business and artificial lift business. We are in the process of divesting the assets and inventory associated with our directional drilling operations. We completed the sale of substantially all of the assets and inventory associated with the artificial lift business on July 2, 2018.
Each reportable segment is described in more detail below. Our results of operations in our core service lines are driven primarily by five interrelated, fluctuating variables: (1) the drilling, completion and production activities of our customers, which is primarily driven by oil and natural gas prices and directly affects the demand for our services; (2) the price we are able to charge for our services and equipment, which is primarily driven by the level of demand for our services and the supply of equipment capacity in the market; (3) the cost of materials, supplies and labor involved in providing our services, and our ability to pass those costs on to our customers; and (4) our activity, or “utilization” levels; and (5) the quality, safety and efficiency of our service execution.
Our management team monitors asset utilization, among other factors, for purposes of assessing our overall activity levels and customer demand. For our Completion Services segment, we measure our asset utilization levels primarily by the total number of days that our asset base works on a monthly basis, based on the available working days per month, which

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excludes scheduled maintenance days. We generally consider an asset to be working such days that it is at or in transit to a job location, regardless of the number of hours worked or whether it generated any revenue during such time. In our Well Construction and Intervention Services segment, we measure our asset utilization levels for our cementing business primarily by the total number of days that our asset base works on a monthly basis, based on the available working days per month. In our coiled tubing business, we measure certain asset utilization levels by the hour to better understand measures between daylight and 24-hour operations. Both the financial and operating performance of our coiled tubing and cement units can vary in revenue and profitability from job to job depending on the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed. In our Well Support Services segment, we measure asset utilization levels primarily by the number of hours our assets work on a monthly basis, based on the available working days per month.
Our operating strategy is focused on maintaining high asset utilization levels to maximize revenue generation while controlling costs to gain a competitive advantage and drive returns. We believe that the safety, quality and efficiency of our service execution and our alignment with customers who recognize the value that we provide are central to our efforts to support utilization and grow our business. Given the volatile and cyclical nature of activity drivers in the U.S. onshore oilfield services industry, coupled with the varying prices we are able to charge for our services and the cost of providing those services, among other factors, operating margins can fluctuate widely depending on supply and demand at a given point in the cycle. For additional information about factors impacting our business and results of operations, please see “Industry Trends and Outlook” in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report.
Completion Services
The core services provided through our Completion Services segment are fracturing and cased-hole wireline and pumping services. We utilize our in-house manufacturing capabilities, including our R&T department and data control instruments business, to offer a technologically advanced and efficiency focused range of completion techniques. The majority of revenue for this segment is generated by our fracturing business.
Fracturing. Our fleet is capable of handling the most technically demanding well completions in conventional and unconventional high-pressure formations. We leverage our R&T capabilities to provide customers with engineered frac designs, refracturing and other reservoir stimulation services that help regain production and increase well recovery. We also can provide our services using smaller frac fleets in response to customer demand for vertical fracs and restimulation services.
Cased-hole Wireline and Pumping. Through our cased-hole wireline and pumping services business, we are one of the leading providers of perforating, pumpdown, pipe recovery, pressure pumping, and wellsite make-up and pressure testing services. We are highly experienced in safely servicing deep, high-pressure, high-temperature wells in some of the most active onshore basins in the United States and provide premium perforating services for both wireline and tubing-conveyed applications. Our in-house manufacturing capabilities through our R&T department allow us to manage costs and lead times with regard to hardware and perforating guns, switches and accessories, providing us with a competitive advantage and enabling higher returns.
Well Construction and Intervention Services
Cementing. Following the closing of the O-Tex Transaction, we are one of the largest providers of specialty cementing services in the United States. Our operations are supported by multiple full-service laboratory facilities with advanced capabilities.
Coiled Tubing. We offer a complete range of coiled tubing services to help customers accomplish a wide variety of goals in their horizontal completion, workover and well maintenance projects. The majority of our coiled tubing fleet consists of large diameter coil, meaning two inches or larger in diameter, which allows us to service wells with longer lateral lengths. Our coiled tubing services allow customers to complete projects quickly and safely across a wide spectrum of pressures, without having to shut in their wells.
Well Support Services
Our Well Support Services segment focuses on post-completion activities at the well site, and includes rig services, such as workover, fluids management, and other specialty well site services. Although we previously provided artificial lift applications through this segment, we completed the sale of substantially all of the assets and inventory associated with this

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business on July 2, 2018. The majority of revenue for this segment is generated by our rig services business, and we consider our rig services and fluids management businesses to be our core service lines within this reportable segment.
Rig Services. As part of our services that help prolong the productive life of an oil or gas well, we operate one of the largest fleets in the United States. These rigs are involved in the routine repair and maintenance of oil and gas wells, re-drilling operations and plug and abandonment operations. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover. Maintenance services provided with our rig fleet are generally required throughout the life cycle of an oil or gas well. Examples of these maintenance services include routine mechanical repairs to the pumps, tubing and other equipment, removing debris and formation material from wellbores, and pulling rods and other downhole equipment from wellbores to identify and resolve production problems. Maintenance services are generally less complicated than completion and workover related services and require less time to perform. Our rig fleet is also used in the process of permanently shutting-in oil or gas wells that are at the end of their productive lives. These plugging and abandonment services generally require auxiliary equipment in addition to a well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and gas because well operators are required by state regulations to plug wells that are no longer productive.
Fluids Management. We provide a full range of fluid services, including the storage, transportation and disposal of various fluids used in the drilling, completion and workover of oil and gas wells. Our fleet of trucks and trailers and portable tanks enable us to rapidly deploy our equipment across a broad geographic area. Included in our fleet of fluid trucks and trailers are specialized trucks and trailers that are optimized to transport condensate. We also own private salt water disposal wells. Demand and pricing for our fluids management services generally correspond to demand for our rig services.
Other Information About Our Business
Seasonality
Our operations are subject to seasonal factors and our overall financial results reflect the seasonal variations that impact activity in our core business lines. Specifically, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. Additionally, our operations are directly affected by weather conditions. During the winter months our customers may delay operations or we may not be able to operate or move our equipment between locations during periods of heavy snow, ice or rain, and during the spring some areas impose transportation restrictions due to the muddy conditions caused by the spring thaws. During the summer months, our operations may be impacted by tropical weather systems.
Sales and Marketing
Sales of our core business lines are primarily generated by the efforts of our sales force, working closely with our operations teams.
Sales and marketing activities are typically performed through our local operations in each geographic region, as well as through our corporate sales teams in Houston.  For our other core business lines, we believe our local field sales personnel have a strong understanding of region-specific issues and customer operating procedures and, therefore, can effectively target marketing activities. We also have multiple corporate sales representatives that supplement our field sales efforts and focus on large accounts and selling technical services. Our sales representatives collaborate with our legal team to identify customer contracting needs in advance of potential operations, which we believe helps streamline our customer onboarding process. Our sales representatives work closely with our local managers and field sales personnel to target compelling market opportunities. Our ability to deliver integrated services through the life of the well and strong track record provides cross-selling and bundling opportunities with existing customers. We facilitate teamwork among our sales representatives by basing a portion of their compensation on aggregate company sales targets rather than individual sales targets. We believe this emphasis on teamwork enables us to better serve our existing customers and may also allow us to further expand our customer base, including through cross-selling and bundling opportunities.
We offer relatively short-term services that generally are cancelable at any time, and as such have no backlogs.

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Customers
We serve a diverse group of independent and major national oil and gas companies that are active in our core areas of operations across the continental United States. We seek customers who value our technology, safety priorities and efficiency capabilities. We monitor the financial condition of our customers, their capital expenditure plans and other indications of their drilling, completion and production services activity. In particular, we seek to identify distressed customers and apply what we believe to be appropriate business and legal measures to protect us from any defaults or failures to pay.
Our top ten customers accounted for approximately 44.2%, 40.7% and 46.0% of our consolidated revenue for the years ended December 31, 2018, 2017 and 2016, respectively. There were no individual customers that accounted for more than 10.0% of our consolidated revenues during the years ended December 31, 2018, 2017 and 2016. If we were to lose any material customer or group of customers that were material in the aggregate, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.
Competition
We operate in highly competitive areas of the oilfield services industry with significant potential for excess capacity. Equipment can be moved from one region to another in response to changes in levels of activity and market conditions, which may result in an oversupply of assets relative to activity in any particular area. Utilization and pricing for our services have from time to time been negatively affected by increases in supply relative to demand in our operating areas and geographic markets.
The demand for our services depends primarily on the level of spending by oil and gas companies for drilling, completion and production activities, which is affected by short-term and long-term trends in oil and natural gas prices and numerous other factors over which we have no control. Severe declines and sustained weakness and volatility in commodity prices may negatively impact the level of drilling, completion and production activity and capital expenditures by our customers, adversely affected the demand for our services. This, in turn, may negatively impact our ability to maintain adequate utilization of our asset base and to negotiate pricing at levels generating sufficient margins.
Our revenues and earnings are directly affected by changes in the utilization of our assets and pricing for our services, which fluctuate in direct response to changes in the level of drilling, completion and production activity by our customers. Pressure on pricing for our services, including due to competition and industry and/or economic conditions, may impact, among other things, our ability to maintain utilization and profitability. During periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results. Furthermore, even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset any rising costs. 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 our costs increase, could have a material adverse effect on our business, financial position and results of operations.
Our competitors include many large and small energy service companies, including some of the largest integrated oilfield services companies that possess substantially greater financial and other resources than we do. Our larger competitors may be able to compete more effectively than we can, including by reducing prices to levels that we cannot sustain for our services. Our major competitors for both our Completion Services and Well Construction and Intervention Services segments include Halliburton, Schlumberger, BJ Services, Keane Group, RPC, Inc., FTS International, Inc., ProPetro Holding Corp., Basic Energy Services, Superior Energy Services, CalFrac Well Services, as well as a significant number of regional, predominantly private businesses. Our major competitors for our Well Support Services include Key Energy Services, Basic Energy Services, Superior Energy Services, Precision Drilling, Forbes Energy Services, Pioneer Energy Services and Ranger Energy Services, as well as a significant number of predominantly private, regional businesses.
Generally, we believe that the principal competitive factors in the markets that we serve are price, technical expertise, equipment capacity and quality, work force capability, safety record, reputation and experience. Although we believe our customers consider all of these factors, price is often the primary factor in determining which service provider is awarded work, particularly during times of weak or volatile commodity prices. Additionally, projects for certain of our core services are often awarded on a bid basis, which tends to further increase competition based primarily on price. During a downturn, our utilization and pricing levels may also be negatively impacted by predatory pricing from certain large competitors, who elect to operate at negative margins in attempt to gain or retain market share.

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During healthier market conditions, we believe many of our customers choose to work with us based on our life-of-well capabilities, geographic footprint and scale, reputation for safety, the quality of our crews, equipment and services, and our value-added technology, although we must always be competitive in our pricing. We seek to differentiate ourselves from our major competitors by our operating philosophy, which is focused on delivering the highest quality customer service and equipment, safely and with superior execution and operating efficiency. As part of this strategy, we seek customers who are aligned with our strengths and want dedicated services, and we target high volume, high efficiency customers with service intensive, 24-hour work, which is where we believe we can differentiate our services from our competitors.
See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Industry Trends and Outlook” for additional discussion of the market challenges within our industry.
Research & Technology, Intellectual Property
Over the last several years we have significantly invested in technological advancement, including the development of a state-of-the-art research and technology center staffed by a team of highly skilled engineers. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our service offerings, increase efficiencies, provide cost savings to our operations and add value for our customers. Our R&T initiatives generate monthly cost savings for our integrated completion services operations, which is central to our overall strategy of proactively managing our costs to maximize returns. Several of these investments provide value added products and services that, in addition to producing revenue, are creating increasing demand from key customers. In our day-to-day operations, we utilize equipment and products manufactured by our vertically integrated businesses which are managed through our R&T department, and we also sell such equipment and products to third-party customers in the global energy services industry. We believe that our focus on R&T provides a significant strategic benefit through the ability to develop and implement new technologies and quickly respond to changes in customer requirements and industry demand.
We seek patent and trademark protection for our technology when we deem it prudent, and we aggressively pursue protection of these rights. We believe our patents and trademarks are adequate for the conduct of our business and that no single patent or trademark is critical to our business. We also rely, to a significant extent, on the technical expertise and know-how of our personnel to maintain our competitive position.
See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional detail as to our investment in technological advancement.
Suppliers
We purchase raw materials (such as proppant, guar, acid, chemicals, completion fluids, cement and coiled tubing strings) and finished products (such as fluid ends, valves, power ends and pump consumables) used in our Completion Services segment and our Well Construction and Intervention Services segment and certain raw materials and finished products used in our Well Support Services segment from various third-party suppliers.
We are not materially dependent on any single supply source for the materials or products that are critical to our operations, and we believe that we would be able to make satisfactory alternative arrangements in the event of any interruption in the supply or recall of these materials and/or products by one of our suppliers. However, if alternative sources of supply are unavailable and we are unable to purchase the necessary materials and/or products needed for our business in a timely manner and in the quantities required, we may be delayed in providing our services, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. For example, in the past, our industry has faced sporadic guar and proppant shortages and trucking shortages associated with hydraulic fracturing operations requiring work stoppages, which adversely impacted the operating results of several of our competitors. Additionally, increasing costs of certain raw materials, such as guar, may negatively impact demand for our services or the profitability of our business operations.
During the year ended December 31, 2018, one supplier from our Well Completions Services segment, Covia Corporation, supplied 7.2%, of our total Company's materials and/or products; but no single third-party supplier from our Well Construction and Intervention Services segment and Well Support Services segment supplied 5.0% or more of the Company's materials and/or products. In conjunction with the sale of our manufacturing business line, we also entered into a preferred supply agreement with a third-party to supply us with components and finished goods to repair and refurbish certain of our hydraulic fracturing equipment.

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Quality, Health, Safety and Environmental (QHSE) Program
Our business involves the operation of extremely heavy and powerful equipment and the use of explosive and radioactive materials, among other hazards. If not well managed, these operations have the potential to result in serious injuries to our employees and/or third-parties and substantial damage to property or the environment. We commit significant resources towards employee safety and have a robust new hire program. We also have comprehensive QHSE-focused training programs designed to minimize accidents in the workplace and improve the safety, quality and efficiency of our operations. We believe that our QHSE policies, standards and procedures, which are reviewed internally for compliance with industry changes, provide a reliable framework to ensure our operations minimize the hazards inherent in our work and meet regulatory requirements and customer demands. Further, we are in the process of implementing a quality management system that will create standardization of processes throughout all facets of our business, support our risk mitigation strategy and help ensure compliance with our procedures and processes.
Our record and reputation for safety are important to all aspects of our business. In the oilfield services industry, a critical competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. In recent years, many of our larger customers have placed an added emphasis on the safety records and quality management systems of their contractors. We strive to meet or exceed the safety and quality management requirements of our customers, and we believe our continued focus on safety will gain even further importance to our customers as the market continues to improve. Our reputation and proven safety record have allowed us to earn work certifications from several industry leaders that we believe have some of the most demanding safety requirements, including ConocoPhillips, ExxonMobil, Chevron and Royal Dutch Shell.
Risk Management and Insurance
Our operations are subject to hazards inherent in the oil and gas industry, including blowouts, explosions, cratering, fires, oil spills, surface and underground pollution and contamination, hazardous material spills, loss of well control, damage to or loss of the wellbore, formation or underground reservoir, damage or loss from the use of explosives and radioactive materials, and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, loss of oil and natural gas production, suspension of operations or loss of license to conduct business, damage to or destruction of the environment and natural resources and damage to or destruction of the property of others. Additionally, our business involves, and so is subject to hazards associated with, the transportation of heavy equipment and materials, as well as heavily regulated explosive and radioactive materials. Regularly having a significant number of both commercial and non-commercial motor vehicles on the road creates a high risk of vehicle accidents that may result in personal injury or death, damage to or destruction of equipment and the property of others and hazardous material spills. The occurrence of a serious accident involving our employees, equipment and/or services, could result in C&J being named as a defendant in lawsuits asserting large claims for damages. C&J could also be liable to indemnify certain third-parties, specifically including its customers, for large claims for damages in situations where our employees, equipment and/or services were involved.
Despite our efforts to maintain high safety and security standards, we from time to time have suffered accidents, outages, breaches, and other incidents, and it is likely that we will experience the same in the future. In addition to the property and personal losses from these events, the frequency and severity of these incidents affect our operating costs and insurability, as well as our relationship with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations. In addition, our business relies heavily on sophisticated information technology systems and infrastructure, the failure of which may cause disruptions to our operations. Any such failure, whether resulting from outages, employee error, cyber-attacks, or other similar events, may have an adverse impact on our financial condition.
We carry a variety of insurance coverages for our operations including coverage for workers’ compensation and employers liability, automobile liability, general liability, which also includes sudden and accidental pollution insurance, environmental liability, and property damage relating to catastrophic events, together with excess loss liability coverage. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis at levels we believe to be customary and reasonable. We have deductibles per occurrence for: workers’ compensation and employers liability claims of $1,000,000; automobile liability claims of $1,000,000; general liability claims, including sudden and accidental pollution claims, of $250,000, plus an additional annual aggregate deductible of $250,000; environmental liability claims of $500,000; and property damage for catastrophic events of $50,000. The excess loss liability coverage is subject to a self-insured retention of $5,000,000 for each occurrence and in the aggregate. We also carry coverage applicable to a number of cyber liabilities,

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including cyber extortion, security failures, and network interruptions. These cyber liability coverages are subject to a self-insured retention of $100,000 for each occurrence.
With respect to the C&P Business that we acquired from Nabors in the Nabors Merger, and as a result of the settlement agreement negotiated with Nabors in connection the Chapter 11 Proceeding, we assumed, among other liabilities, all liabilities of the C&P Business to the extent arising out of or resulting from the operation of the C&P Business at any time before, at or after the closing of the Nabors Merger, including liability for death, personal injury and property damage resulting from or caused by the assets, products and services of the C&P Business, other than those liabilities specifically identified in the settlement agreement, as incorporated into the Restructuring Plan, for which Nabors maintains a continuing indemnification obligation. Please see “U.S. Department of Justice Criminal Investigation into Pre-Nabors Merger Incident” in Part I, Item 3 “Legal Proceedings” for additional information about the certain legal proceedings related to the C&P Business.
As discussed below, our Master Service Agreements (“MSAs”) with our customers generally provide, among other things, that our customers generally assume (without regard to fault) liability for underground pollution and pollution emanating from the wellbore as a result of an explosion, fire or blowout. We retain the risk for any liabilities which we cause, and which are not otherwise indemnified by our customers. This includes liability to indemnify our customer for certain liabilities. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements.
We strive to enter into MSAs with each of our customers before providing any services. Our sales and operations teams work closely with our legal team to identify and prioritize MSAs for negotiation, which we believe increases the efficiency of our risk management efforts. These MSAs delineate our and our customers’ respective warranty and indemnification obligations with respect to the services we provide. With respect to warranty issues, our MSAs typically provide that our obligations are limited to replacing any defective good or services, or in the alternative, providing the customer with a refund. Our MSAs typically provide for knock-for-knock indemnification for all bodily injuries and property losses arising from our work, which means that we and our customers assume (without regard to fault) liability for damages to our respective personnel and property. For catastrophic losses, our MSAs generally include industry-standard carve-outs from the knock-for-knock indemnities, pursuant to which our customers (typically the exploration and production companies) assume (without regard to fault) liability for (i) damage to the well bore, including the cost to re-drill; (ii) damage to the formation, underground strata and the reservoir; (iii) damages or claims arising from loss of control of a well or a blowout; and (iv) allegations of subsurface trespass. Additionally, our MSAs often provide carve-outs to the “without regard to fault” concept that would permit, for example, us to be held responsible for events of catastrophic loss to the extent they arise as a result of our gross negligence or willful misconduct. Our MSAs typically provide for industry-standard pollution indemnities, pursuant to which we assume liability for surface pollution associated with our equipment and originating above the surface (without regard to fault), and our customer assumes (without regard to fault) liability arising from all other pollution, including, without limitation, underground pollution and pollution emanating from the wellbore as a result of an explosion, fire or blowout. In certain circumstances, we agree to exceptions from our MSAs’ catastrophic loss and pollution indemnities to the extent incidents arise from our gross negligence or willful misconduct.
The description of insurance policies set forth above is a summary of certain material terms of our insurance policies currently in effect and may change in the future as a result of market and/or other conditions. Similarly, the summary of MSAs set forth above is a summary of the material terms of the typical MSA that we have in place, but does not reflect every MSA that is in effect or that we may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different and less favorable than those described here.
Employees
As of February 22, 2019, we have 6,399 employees. The delivery of our core completion services requires personnel with specialized skills and experience who can perform physically demanding work. Due to the commodity price volatility often experienced in the energy services industry and the demanding nature of the work, workers often choose to pursue employment in fields that offer a less strenuous work environment. During periods of high demand for oil field services, there can be extreme competition amongst employers to attract and retain skilled workers, which often results in a shortage of qualified employees and attrition due to wage escalation by competitors. Additionally, in our Well Support Services segment we continue to experience labor shortages for qualified drivers with a commercial driver's license and workover rig operators for our rig services business.
Our employees are not represented by any labor unions or covered by collective bargaining agreements. We consider our relations with our employees to be generally good.

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Government Regulations and Environmental, Health and Safety Matters
We are significantly affected by stringent and complex federal, state and local laws and regulations, including those governing worker health and safety, motor carrier operations, the transportation of explosives, the use, management and disposal of certain radioactive materials, the handling of hazardous materials and the emission or discharge of substances into the environment or otherwise relating to environmental protection. Regulations concerning equipment certification create an ongoing need for regular maintenance, which is incorporated into our daily operating procedures. The regulatory burden on the industry increases the cost of doing business and consequently affects profitability. Any failure by us to comply with such local, state and federal laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the following:
issuance of administrative, civil and criminal penalties;
modification, denial or revocation of permits or other authorizations;
imposition of limitations on our operations through injunctions or other governmental actions; and
performance of site investigatory, remedial or other corrective actions.
Worker Health and Safety
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. OSHA has implemented stricter standards for worker exposure to silica, which would apply to use of sand as a proppant for hydraulic fracturing. These new standards require the oil and gas industry to implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021.
Motor Carrier Operations
Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the United States Department of Transportation (“DOT”) and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period and requiring onboard black box recorder devices or limits on vehicle weight and size. For example, in December 2016, the DOT finalized minimum training standards for new drivers seeking a commercial driver’s license. Certain motor vehicle operators are required to register with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria, and a revocation could result in a suspension of operations. Since 2010, the DOT has pursued its Compliance, Safety, Accountability (“CSA”) program, in an effort to improve commercial truck and bus safety. A component of CSA is the Safety Measurement System (“SMS”), which analyzes all safety violations recorded by federal and state law enforcement personnel to determine a carrier’s safety performance. The SMS is intended to allow DOT to identify carriers with safety issues and intervene to address those problems.
Interstate motor carrier operations are subject to safety requirements prescribed by DOT. To a large degree, intrastate motor carrier operations are subject to safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

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Radioactive Materials
In addition, some of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the United States Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. We believe that we have obtained these licenses and approvals as necessary and applicable. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, injunctions prohibiting some or all of our operations, assessment of administrative and civil penalties, and even criminal prosecution. In addition, releases of radioactive material could result in substantial remediation costs and potentially expose us to third-party property damage or personal injury claims.
Hazardous Substances
We generate wastes, including hazardous wastes, which are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”), the NRC, and state agencies have limited the approved methods of disposal for some types of hazardous and nonhazardous wastes. RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.” Disposal of such non-hazardous oil and natural gas exploration, development and production wastes is usually regulated by state law. Other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If the EPA proposes new rulemaking, the 2016 consent decree requires the EPA to take final action on such rules no later than July 15, 2021. Removal of RCRA’s exemption for exploration and production wastes has the potential to significantly increase waste disposal costs, which in turn will result in increased operating costs and could adversely impact our business and results of operations. The impact of future revisions to environmental laws and regulations cannot be predicted.
Naturally Occurring Radioactive Materials (“NORM”) may contaminate extraction and processing equipment used in the oil and natural gas industry. The waste resulting from such contamination is regulated by federal and state laws. Standards have been developed for: worker protection; treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. It is possible that we may incur costs or liabilities associated with elevated levels of NORM.
The Federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or the “Superfund” law), and comparable state statutes impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to have been responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at off-site locations such as landfills. Under CERCLA, these persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and natural gas related operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third-parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes and remediate contaminated property (including groundwater contamination), including instances where the prior owner or operator caused the contamination, or perform remedial plugging of disposal wells or waste pit closure operations to prevent future contamination. These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed.

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Water Discharges
The Federal Water Pollution Control Act (the “Clean Water Act”), and comparable state statutes impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. The Clean Water Act also prohibits the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In September 2015, the EPA and U.S. Army Corps of Engineers (the “Corps”) issued a new rule defining the scope of the EPA’s and the Corps’ jurisdiction over wetlands and other waters. On December 11, 2018, EPA and the Corps issued a proposed new rule that would differently revise the definition of waters of the United States and essentially replace the 2015 rule. According to the agencies, the proposed new rule is intended to increase CWA program predictability and consistency by increasing clarity as to the scope of ‘waters of the United States’ federally regulated under the Act. If finalized, this new definition of waters of the United States will likely be challenged and sought to be enjoined in federal court. Until that time, regulations are being implemented as they were prior to August 2015. A public hearing on this proposed rule was scheduled for January 23, 2019, but this hearing was postponed due to the shutdown of the federal government in early 2019. The process for obtaining permits has the potential to delay the development of natural gas and oil projects. Also, spill prevention, control and countermeasure regulations under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.
In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Moreover, the Oil Pollution Act of 1990 (“OPA”) imposes a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages, including natural resource damages, resulting from such spills in waters of the United States. A responsible party includes the owner or operator of an onshore facility. The Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the OPA, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.
The Safe Water Drinking Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, the EPA has asserted that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program. In addition, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewater, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have imposed volumetric injection limits, shut down or imposed moratorium on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to perform services may be delayed or limited, which could have an adverse effect on our results of operations and financial position.
Air Emissions
Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act (“CAA”) and analogous state laws require permits for certain facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose generally applicable limitations on air emissions and require adherence to maintenance, work practice, reporting and record keeping, and other requirements. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of substantial administrative, civil and even criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional expenses and operational delays.
Many of these regulatory requirements, including New Source Performance Standards and Maximum Achievable Control Technology standards have been made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. Subsequently, in November 2017, the EPA published a list of areas that are in compliance with the new ozone standards and separately in December 2017 issued responses to state recommendation for designating nonattainment areas. Remaining area designations were completed on July 17, 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

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Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase costs for us and our customers. Although we do not believe our operations will be materially adversely affected by these requirements, our business could be materially affected if our customers’ operations are significantly affected by these or other similar requirements. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and gas our customers produce, and thus have an adverse effect on the demand for our products and services.
Climate Change
More stringent laws and regulations relating to climate change may be adopted in the future and could cause us to incur additional operating costs or reduce the demand for our services. The EPA has determined that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to the environment because emissions of such gases are, according to the EPA and many scientists, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations that restrict emissions of GHGs under existing provisions of the CAA, including rules that require preconstruction and operating permit reviews for GHG emissions from certain large stationary sources. In subsequent litigation, the U.S. Supreme Court upheld a portion of the EPA’s GHG stationary source program, but also invalidated a portion of it, holding that stationary sources already subject to the Prevention of Significant Deterioration ("PSD") or Title V program for non-GHG criteria pollutants remained subject to GHG requirements, but that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with EPA’s GHG requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the GHG regulations under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. In October 2016, the EPA issued a proposed rule to further revise its PSD and Title V regulations applicable to GHGs in accordance with these court rulings. This rulemaking process is ongoing. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG sources, including, among others, certain oil and natural gas production facilities, on an annual basis. More recently, in June 2016, the EPA issued final rules that establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing transmission and storage activities. The EPA’s final rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. However, over the past year the EPA has taken several steps to delay implementation of these methane rules, and the agency proposed a rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of the EPA’s methane rules in their entirety. EPA proposed revisions on September 11, 2018, intended to roll back parts of the 2016 rules. The EPA has not yet published a final rule but, as a result of these developments, future implementation of the EPA methane rules is uncertain at this time. In April 2018, a coalition of states filed a lawsuit in federal district court aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. In addition, the EPA finalized rules to further reduce GHG emissions, primarily from coal-fired power plants, under its Clean Power Plan. However, on October 9, 2017, the EPA announced that it will repeal the Clean Power Plan and, on August 21, 2018, proposed the Affordable Clean Energy ("ACE") rule, which would establish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACE rule would replace the Clean Power Plan and the rulemaking process is ongoing. The Bureau of Land Management (“BLM”) also finalized similar rules in November 2016 which seek to limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements for certain equipment and processes. In September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of these regulations; California and New Mexico have challenged the new rule in ongoing litigation. We do not believe our operations are currently subject to these requirements, but, to the extent fully implemented, our business could be affected if our customers’ operations become subject to these or other similar requirements. Moreover, these requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and gas our customers produce, and thus have a material adverse effect on the demand for our products and services.
In addition, while Congress has yet to pass legislation to reduce emissions of GHGs, and almost one-half of the states have established or joined GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. In addition, in 2015, the U.S. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement has a four year exit process. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are

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unclear at this time. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any new federal, regional or state restrictions on emissions of carbon dioxide or other GHGs that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such restrictions could potentially make our customers’ products more expensive and thus reduce demand for such products, which in turn could have a material adverse effect on the demand for our services and our business. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities, which could have a material adverse effect on our business and results of operations. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas our customers produce. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climatic changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly perform hydraulic fracturing services for our customers. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but, as noted above, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance in February 2014 that applies to such activities. In addition, the EPA has taken certain actions noted above and issued final regulations under the CAA governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; and finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants, compliance with which is required by August 2019. Also, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and Native American lands. The BLM issued a final rule in December 2017 repealing its hydraulic fracturing rule, and this action has been challenged in federal court. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may 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.
In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts the ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business. The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also

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designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If our customers were to have areas within their business and operations designated as critical or suitable habitat or a protected species, it could decrease demand for our services and have a material adverse effect on our business.
There have been no material incidents or citations related to our hydraulic fracturing operations in the past five years. During that period, we have not been involved in any litigation over alleged environmental violations, have not been ordered to pay any material monetary fine or penalty with respect to alleged environmental violations, and are not currently facing any type of governmental enforcement action or other regulatory proceeding involving alleged environmental violations related to our hydraulic fracturing operations. In addition, pursuant to our MSAs, we are generally liable for only surface pollution, not underground or flowback pollution, which our customers are generally liable for and for which we are typically indemnified by our customers.
We maintain insurance against some risks associated with underground contamination that may occur as a result of well services activities. However, this insurance is limited to activities at the well site and may not continue to be available or may not be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a materially adverse effect on our financial condition and results of operations.
Overall, we do not anticipate that compliance with existing environmental laws and regulations will have a material effect on our financial condition or results of operations. It is possible, however, that substantial costs for compliance or penalties for non-compliance may be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations, and enforcement policies, could result in additional costs or liabilities that we cannot currently quantify.

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Item 1A. Risk Factors
We face many challenges and risks in the industry in which we operate. Before investing in our common stock you should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report, including under the section titled “Cautionary Note Regarding Forward-Looking Statements”, and in our other reports filed with the SEC, and the documents and other information incorporated by reference herein and therein, for a detailed discussion of known material factors which could materially affect our business, financial condition or future results. The risks and uncertainties described are not the only ones we face. Additional risk factors not presently known to us or which we currently consider immaterial may also adversely affect our business, financial condition or future results. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common stock could decline, and you could lose all or part of your investment.
Risks Related to Our Business and Financial Condition
Our business is cyclical and dependent upon conditions in the oil and natural gas industry that impact the level of exploration, development and production of oil and natural gas and capital expenditures by oil and natural gas companies. Our customers’ willingness to undertake drilling, completion and production activities depends largely upon prevailing industry conditions that are influenced by numerous factors that are beyond our control. Any of these factors could have a material adverse effect on our business, financial condition, results of operations and cash flow.
We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas. If these expenditures decline, our business will suffer. The oil and gas industry has traditionally been volatile, is highly sensitive to supply and demand cycles and is influenced by a combination of long-term, short-term and cyclical trends. Our customers’ willingness to conduct drilling, completion and production activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as:
the supply of and demand for oil and natural gas;
the current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices;
the supply of and demand for hydraulic fracturing and other well service equipment in the continental United States;
the level of global and domestic oil and natural gas inventories;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the ability or willingness of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels for oil;
public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;
the expected rates of decline of current oil and natural gas production;
lead times associated with acquiring equipment and products and availability of personnel;
regulation of drilling activity;
the availability of water resources, suitable proppant and chemicals in sufficient quantities for use in hydraulic fracturing fluids;
the discovery and development rates of new oil and natural gas reserves;
available pipeline and other transportation capacity;
weather conditions, including hurricanes that can affect oil and natural gas operations over a wide area;
political instability in oil and natural gas producing countries, including governmental shutdowns;
domestic and worldwide economic conditions;
technical advances affecting energy consumption;
the price and availability of alternative fuels; and
merger and divestiture activity among oil and natural gas producers.
Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decline) 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 less risk tolerant 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 core service lines, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Spending by exploration and production companies can also be impacted by conditions in the capital markets. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause exploration and production companies to make additional reductions to capital budgets in the future even if oil prices remain at current levels or natural gas prices increase from current levels. Any such cuts in spending may cause our customers to curtail their drilling programs, including completion and production activities and any discretionary spending on well services, which may result in a reduction in the demand for our services, the rates we can charge and the utilization of our assets. Moreover, reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves, in our market areas, whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, could also have a material adverse impact on our business, even in a stronger oil and natural gas price environment.
Fluctuations in oil and natural gas prices could adversely affect drilling, completion and production activities by oil and natural gas companies and our revenues, cash flows and profitability. If oil and natural gas prices remain volatile, or if oil or natural gas prices decline, the demand for our services could be adversely affected.
The demand for our services depends on the level of spending by oil and 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 so. For example, during 2018, NYMEX crude oil prices averaged approximately $65.00 per barrel, and during 2018 NYMEX crude oil prices ranged from approximately $76.00 to $43.00 per barrel. During periods of declining oil and natural gas prices, or when pricing remains depressed, we have experienced significant declines in drilling, completion and production activities across our customer base, which in turn resulted in reduced demand and increased competition and pricing pressure to varying degrees across our service lines and operating areas. If the prices of oil and natural gas continue to be weak and volatile, our business, financial condition, results of operations, cash flows and prospects may be materially and adversely affected.
Worldwide military, political and economic events, including initiatives by OPEC, affect both the demand for, and the supply of, oil and natural gas. Weather conditions, governmental regulation (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity and other factors that will be beyond our control may also affect the supply of, demand for, and price of oil and natural gas. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower completion and production spending on existing wells. This, in turn, could result in lower demand for our services and cause lower pricing and utilization levels for our services. If oil and natural gas prices decline, or if there is a further reduction in drilling and completion activities, the demand for our services and our results of operations could be materially and adversely affected.
The oilfield services industry is highly competitive with significant potential for excess capacity. We may not be able to meet the specific needs of oil and natural gas exploration and production companies at competitive prices which could adversely affect our business and operating results.
The oilfield services industry is highly competitive. The principal competitive factors in our markets are generally price, technical expertise, the availability and condition of equipment, work force capability, safety record, reputation and experience. We compete with large national and multi-national companies that have longer operating histories, greater financial resources and greater name recognition than we do and who can operate and have operated at a loss in the regions in which we operate. Additionally, some of our competitors provide a broader array of services and/or have a stronger presence in more geographic markets. Our reputation for safety and quality may not be sufficient to enable us to maintain our competitive position, and our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Increases in market capacity can lead to active price competition, which could adversely affect our business and utilization levels.
Significant increases in overall market capacity have caused active price competition and led to lower pricing and utilization levels for our services. Completion and well servicing equipment, such as hydraulic fracturing fleets, can be moved from one region to another in response to changes in levels of activity and market conditions, which may result in an oversupply of equipment in an area. For example, natural gas prices declined sharply in 2009 and remained depressed through 2015, which resulted in reduced drilling activity in natural gas shale plays. This drove many oilfield services companies operating in those areas to relocate their equipment to more oil- and liquids-rich shale plays, such as the Eagle Ford Shale and Permian Basin. As drilling activity and completion capacity migrated into the oil- and liquids-rich regions from the gas-rich

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regions, the increase in supply relative to demand negatively impacted pricing and utilization of our services, particularly for hydraulic fracturing services. Furthermore, as we entered 2015, we experienced a slowdown in activity across our customer base as operators reacted to the rapid decline in commodity prices that began during the fourth quarter of 2014. The entire year proved to be extremely challenging for the North American oilfield services industry due to the sustained weakness and volatility in oil prices at levels that caused severe reductions in drilling, completion and production activities, which in turn resulted in reduced demand and increased competition and pricing pressure to varying degrees across our service lines and operating areas.
We may be unable to implement price increases or maintain existing prices on our core services.
We generate revenue from our core service lines, many of which are provided on a spot market basis. Pressure on pricing for our core services, including due to competition and industry and/or economic conditions, may impact, among other things, our ability to implement price increases or maintain pricing on our core services. We operate in a very competitive industry and, as a result, we may not always be successful in raising, or maintaining our existing prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including hydraulic fracturing equipment, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase or maintain prices. Furthermore, during periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our profitability.
Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset such rising costs. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our prices or to increase our prices as costs increase could have a material adverse effect on our business, financial position and results of operations.
Reliance upon a few large customers may adversely affect our revenue and operating results.
Our top ten customers represented approximately 44.2%, 40.7% and 46.0% of our consolidated revenue for the years ended December 31, 2017, 2016 and 2015, respectively. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer fails to pay us, revenue would be impacted, and our operating results and financial condition could be harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.
Weather conditions could materially impair our business.
Our operations and the operations of our customers may be adversely affected by seasonal weather conditions, severe weather events and natural disasters. For example, prolonged periods of drought, hurricanes, tropical storms, heavy snow, ice or rain may result in customer delays and other disruptions to our services. Repercussions of adverse weather conditions may include:
curtailment of services;
weather-related damage to facilities and equipment, resulting in suspension of operations;
inability to deliver equipment, personnel and products to job sites in accordance with contract schedules;
increase in the price of insurance; and
loss of productivity.

These constraints could also delay our operations, reduce our revenue and materially increase our operating and capital costs.
Our operations are subject to hazards inherent in the oilfield services industry.
Risks inherent to our industry, such as equipment defects, vehicle accidents, explosions and uncontrollable flows of gas or well fluids, can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruption and damage to, or destruction of property, equipment and the environment. For example, transportation of heavy equipment creates the potential for our trucks to become involved in roadway accidents, which in turn could result in personal injury or property damages lawsuits being filed against us. In addition, our hydraulic fracturing and well completion services could become a source of spills or releases of fluids, including chemicals used during hydraulic fracturing activities, at the site where such services are performed, or could result in the discharge of such fluids into underground formations that were not targeted for fracturing or well completion activities, such as potable aquifers. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages and could result in a variety of claims, losses and remedial obligations that could have a material

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adverse effect on our business and results of operations. The existence, frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable, which could cause us to lose customers and substantial revenue.
Our operational personnel have experienced accidents which have, in some instances, resulted in serious injuries. Our safety procedures may not always prevent such damages. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations and cash flows.
Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues.
Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our facilities or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs.
We may be unable to employ a sufficient number of key employees, technical personnel and other skilled and 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 in fields that offer a different work environment. Our ability to be productive and profitable depends upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. At times, demand for skilled workers in our geographic area of operations is high, and the supply is limited. 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 pay, or both. If either of these events were to occur, our capacity and profitability could be diminished, and our growth potential could be impaired.
We depend heavily on the efforts of our 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.
Delays in deliveries of key raw materials or increases in the cost of key raw materials could harm our business, results of operations and financial condition.
We have established relationships with a limited number of suppliers of our raw materials (such as proppant, guar, chemicals or coiled tubing) and finished products (such as fluid-handling equipment). Should any of our current suppliers be unable to provide the necessary raw materials or finished products or otherwise fail to deliver the products in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, increasing costs of certain raw materials, including guar, may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic shortages associated with hydraulic fracturing operations, such as proppant and guar, requiring work stoppages, which adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of raw materials, including proppants.
We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers.

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Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the natural gas or crude oil markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us.
Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment.
Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. The costs of components and labor required to maintain our fleets have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs to make our remaining active fleets operational. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, refurbishment or upgrades. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. 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 hydraulic fracturing fleets and other completion service related equipment and the increase in cost to maintain labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase the cost to make our inactive fleets operational.
We participate in a capital-intensive industry, and we may not be able to finance future growth of our operations or future acquisitions, which could adversely affect our operations and financial position.
The successful execution of our growth strategy depends on our ability to generate sufficient cash flows and our access to capital, both of which are impacted by numerous factors beyond our control, including financial, business, economic and other factors, such as volatility in commodity prices and pressure from competitors. Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Continued low commodity prices, among other factors, have caused some lenders to increase interest rates, enact tighter lending standards which we may not satisfy as a result of our debt level or otherwise, refuse to refinance existing debt at maturity on favorable terms or at all, and in certain instances have reduced or ceased to provide funding to borrowers.
If we are unable to generate sufficient cash flows or to access the capital and credit markets on favorable terms or at all, we may be unable to continue growing our business, conduct necessary corporate activities, take advantage of business opportunities that arise or engage in activities that may be in our long-term best interest, which may adversely impact our ability to sustain or improve our current level of profitability. Furthermore, any failure to make scheduled payments of interest and principal on our outstanding indebtedness could harm our ability to incur additional indebtedness on acceptable terms or at all, and also could constitute an event of default under our Credit Facility. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects, and we could be forced into bankruptcy or liquidation.
Disruptions in the capital and credit markets, continued low commodity prices, our debt level and other factors may restrict our ability to raise capital on favorable terms, or at all.
Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Continued low commodity prices, among other factors, have caused some lenders to increase interest rates, enact tighter lending standards which we may not satisfy as a result of our debt level or otherwise, refuse to refinance existing debt at maturity on favorable terms, or at all, and in

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certain instances have reduced or ceased to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms or at all, it could adversely affect our business, financial condition and results of operations.
We are subject to restrictive covenants in our Credit Facility, which may restrict our operational flexibility.
The Credit Facility governing our indebtedness contains, and future debt agreements may contain, financial and other restrictive covenants that may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, conduct necessary corporate activities, take advantage of business opportunities that arise and/or to engage in activities that may be in our long-term best interests.
Specifically, our Credit Facility includes a Fixed Charge Coverage Ratio and minimum liquidity threshold covenants and restrictive covenants that limit our ability and that of our subsidiaries to, among other things:
sell or otherwise dispose of assets;
make certain restricted payments and investments;
create, incur, assume, suffer to exist or guarantee additional indebtedness;
create, incur, assume, or suffer to exist liens on our assets;
make capital expenditures, investments or acquisitions;
repurchase, redeem or retire our capital shares;
merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;
engage in specified transactions with subsidiaries and affiliates; and
pursue other corporate activities.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by restrictive covenants under the Credit Facility, which could: limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise restrict our activities or business plan; and adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.
Please see “Liquidity and Capital Resources - Description of Our Indebtedness - Credit Facility” in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information about the Credit Facility, including the financial and other restrictive covenants contained therein.
We may not be able to service our debt obligations in accordance with their terms.
On May 1, 2018, we entered into a new asset-based revolving credit agreement (the “Credit Facility”). Our ability to meet our debt service obligations under, and comply with the financial covenants contained in, our Credit Facility or future debt agreements depends on our future performance, which is affected by financial, business, economic and other factors, many of which are beyond our control, including volatility in commodity prices and pressure from competitors. Should our revenues decline, we may not be able to generate sufficient cash flow to pay our debt service obligations when due. Additionally, revenue, utilization and pricing level declines may result in our not being in compliance with one or more of the financial covenants under our Credit Facility or future debt agreements in future periods. Any failure to satisfy our debt obligations or to comply with the applicable financial covenants could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects.
If we are unable to meet our debt service obligations or should we fail to comply with, or obtain relief from, the financial and other restrictive covenants contained in our Credit Facility or future debt agreements, we may trigger an event of default. Upon such an event of default, our lenders may refuse to fund borrowings and have the right to terminate their commitments and potentially accelerate all of our outstanding debt. If an event of default occurs and the lenders under our Credit Facility or future debt agreements accelerate the maturity of any loans or other debt outstanding. We may not be able to make all required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing is available at that time it may not be on terms that are acceptable to us.
Any reduction of the borrowing base under our Credit Facility could require us to repay that portion of indebtedness that exceeds the new borrowing base under our Credit Facility earlier than anticipated, which could adversely impact our liquidity.
Our Credit Facility allows us to borrow amounts up to the lesser of $400 million and a borrowing base based on the value of our eligible accounts receivable, inventory and restricted cash. Currently, our borrowing base is $234.7 million. Reductions in accounts receivable and inventory due to events or market forces beyond our control could reduce the amount available to us under our Credit Facility and could result in a redetermination, and potentially a reduction, of our borrowing

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bases under our Credit Facility. If our Credit Facility eventually becomes fully drawn, any reduction in the borrowing bases could require us to make mandatory prepayments under our Credit Facility to the extent existing indebtedness under the Credit Facility exceeds the borrowing base. We may have insufficient cash on hand to be able to make mandatory prepayments under our Credit Facility. Any failure to repay indebtedness in excess of our borrowing bases in accordance with the terms of the Credit Facility would constitute an event of default under the Credit Facility. Such event of default would permit our lenders to accelerate our outstanding debt, which if actually accelerated, would become immediately due and payable and could permit our secured lenders to foreclose on any of our assets securing indebtedness.
As a result of the implementation of our Restructuring Plan, we believe our ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes may be subject to limitation under Section 382.
Under U.S. federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses (“NOLs”) carried forward from prior years. As of December 31, 2018, we reported consolidated federal NOL carryforwards of approximately $1.3 billion of which $454.8 million are pre-change NOL's subject to limitation. Our ability to utilize our NOL carryforwards to offset future taxable income and to reduce U.S. federal income tax liability is subject to certain requirements and restrictions. In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOLs to offset future taxable income. An ownership change generally occurs if one or more shareholders (or groups of shareholders) who are each deemed to own at least 5% of our stock have aggregate increases in their ownership of such stock of more than 50 percentage points over such stockholders’ lowest ownership percentage during the testing period (generally a rolling three year period). We believe we experienced an ownership change in January 2017 as a result of the implementation of the Restructuring Plan and that our pre-change NOLs are subject to limitation under Section 382 of the Code as a result. Such limitation may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitation were not in effect and could cause our pre-change NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes.
As a result of the implementation of our Restructuring Plan, NOLs and other tax attributes may be subject to reduction, causing less NOL or tax deductions to be available to offset future taxable income for U.S. federal income tax purposes.
As a result of consummating our Restructuring Plan, the obligations of the Predecessor with respect to the Original Credit Agreement (the “Old C&J Debt”) were canceled and discharged and certain lenders were issued common stock in the reorganized Company (See Note 14 - Chapter 11 Proceeding and Emergence). This exchange may give rise to cancellation of debt income (“CODI”) to the extent that the fair market value of the common stock and other rights exchanged with the lenders is less than the adjusted issue price of the Old C&J Debt. Other settlements with holders of Claims under the Restructuring Plan may have resulted in satisfaction of debts for less than the amount of the liability resulting in CODI. The Code provides that CODI arising under a discharge in a Chapter 11 bankruptcy proceeding is excluded from taxable income. A taxpayer excluding CODI under these circumstances may be required to reduce certain tax attributes, such as NOLs and depreciable basis by an amount up to the amount of excluded CODI (the “Tax Attribute Reduction Rules”). As of December 31, 2018, there are a number of significant claims under the Restructuring Plan that remain outstanding. We will continue to monitor these claims and make estimates accordingly.
We are vulnerable to the potential difficulties associated with growth, mergers, acquisitions and expansion.
We believe that our future success depends on our ability to take advantage of and manage rapid growth, as well as the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:
lack of sufficient executive-level personnel;
increased administrative burden;
long lead times associated with acquiring additional equipment;
ability to manage significant levels of idle equipment in sustained periods of depressed oil and natural gas prices;
ability to maintain the level of focused service attention that we have historically been able to provide to our customers; and
new or expanded areas of operational risk (such as offshore or international operations) and related costs and demands of any applicable regulatory compliance.
In addition, in the future we may seek to grow our business through acquisitions that enhance our existing operations. The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may

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require a disproportionate amount of our managerial and financial resources. Our operating results could be adversely affected if we do not successfully manage these potential difficulties in integrating the businesses we may acquire.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect demand for our support services.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly perform hydraulic fracturing services for our customers.
Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance in February 2014 that applies to such activities. Also, in May 2014, the EPA published an advanced notice of proposed rulemaking under the Toxic Substances and Control Act (“TSCA”) that would require the disclosure of chemicals used in hydraulic fracturing fluids; however, to date no further action has been taken and additional rulemaking under TSCA appears unlikely at this time. In addition, in June 2016, the EPA finalized regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may 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. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.
Various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction, and temporary or permanent bans on hydraulic fracturing in certain areas. For example, in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In addition, state and federal regulatory agencies have recently focused on a possible connection between the disposal of wastewater in underground injection wells and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In response to these concerns, regulators in some states are seeking to impose additional requirements on hydraulic fracturing fluid disposal practices, including restrictions on the operations of produced water disposal wells and imposing more stringent requirements on the permitting of such wells. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from our customer’s activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our fluid transportation business, financial condition and results of operations.
Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business.
The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, increase our costs of compliance and adversely affect the hydraulic fracturing services that we render for our exploration and production customers. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

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Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for our services.
The EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act.
From time to time the U.S. Congress has considered legislation to reduce emissions of GHGs, and almost one-half of the states have established GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
Any new federal, regional or state restrictions on emissions of GHGs that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such actions could also potentially make our customers’ products more expensive and thus reduce demand for those products, which could have a material adverse effect on the demand for our services and our business. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities, which could have a material adverse effect on our business and results of operations. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas our customers produce. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, many scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our results of operations if they were to damage our equipment or facilities.
We are subject to extensive and costly environmental, and occupational health and safety laws, and regulations that may require us to take actions that will adversely affect our results of operations.
Our business is significantly affected by stringent and complex federal, state and local laws and regulations governing the emission or discharge of substances into the environment, protection of the environment and worker health and safety. Any failure by us to comply with such environmental and occupational health and safety laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the following:
issuance of administrative, civil and criminal penalties;
modification, denial or revocation of permits or other authorizations;
imposition of limitations on our operations or orders prohibiting our operations altogether; and
performance of site investigatory, remedial or other corrective actions.
As part of our business, we handle, transport, and dispose of a variety of fluids and substances used by our customers in connection with their oil and natural gas exploration and production activities. We also generate and dispose of nonhazardous and hazardous wastes. The generation, handling, transportation, and disposal of these fluids, substances, and wastes are regulated by a number of laws, including CERCLA, RCRA, Clean Water Act, SDWA and analogous state laws. Under RCRA, the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes are regulated. RCRA currently exempts many exploration and production wastes from classification as hazardous waste. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous waste in the future.
Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to liability for governmental penalties, third-party claims, cleanup costs associated with releases of such materials, damages to natural resources, and other damages, as well as potentially impair our ability to conduct our operations. Moreover, certain of these environmental laws impose joint and several, strict liability even though our conduct in performing such activities was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third-parties was the basis for such liability. In addition, environmental laws and

25


regulations are subject to frequent change and if existing laws, regulatory requirements or enforcement policies were to change in the future, we may be required to make significant unanticipated capital and operating expenditures.
Anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.
We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations.
New technology may hurt our competitive position.
The energy service industry is subject to the introduction of new techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, 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 than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations.
We may be adversely affected by disputes regarding intellectual property rights and the value of our intellectual property rights is uncertain.
We may become involved in dispute resolution proceedings from time to time to protect and enforce our intellectual property rights. In these dispute resolution proceedings, a defendant may assert that our intellectual property rights are invalid or unenforceable. Third parties from time to time may also initiate dispute resolution proceedings against us by asserting that our businesses infringe, impair, misappropriate, dilute, or otherwise violate another party’s intellectual property rights. We may not prevail in any such dispute resolution proceedings, and our intellectual property rights may be found invalid or unenforceable or our products and services may be found to infringe, impair, misappropriate, dilute, or otherwise violate the intellectual property rights of others. The results or costs of any such dispute resolution proceedings may have an adverse effect on our business, operating results, and financial condition. Any dispute resolution proceeding concerning intellectual property could be protracted and costly, is inherently unpredictable, and could have an adverse effect on our business, regardless of its outcome.
Our success may be affected by the use and protection of our proprietary technology. There are limitations to our intellectual property rights and, thus, our right to exclude others from the use of such proprietary technology.
Our success may be affected by our development and implementation of new product designs and improvements and by our ability to protect, obtain, and maintain intellectual property assets related to these developments. We rely on a combination of patents and trade secret laws to establish and protect this proprietary technology. We have received patents and have filed patent applications with respect to certain aspects of our technology, and we generally rely on patent protection with respect to our proprietary technology, as well as a combination of trade secrets and copyright law, employee and third-party non-disclosure agreements, and other protective measures to protect intellectual property rights pertaining to our products and technologies. We cannot assure you that competitors will not infringe upon, misappropriate, violate, or challenge our intellectual property rights in the future. If we are not able to adequately protect or enforce our intellectual property rights, such intellectual property rights may not provide significant value to our business, results of operations, or financial condition.
Moreover, our rights in our confidential information, trade secrets, and confidential know-how will not prevent third parties from independently developing similar technologies or duplicating such technologies. Publicly available information (e.g., information in issued patents, published patent applications, and scientific literature) can be used by third parties to independently develop technology, and we cannot provide assurance that this independently developed technology will not be equivalent or superior to our proprietary technology. In addition, while we have patented some of our key technologies, we do not patent all of our proprietary technology, even when regarded as patentable. The process of seeking patent protection can be long and expensive. There can be no assurance that patents will be issued from currently pending or

26


future applications or that, if patents are issued, they will be of sufficient scope or strength to provide meaningful protection or any commercial advantage to us.
We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
As of December 31, 2018, we are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.
Our operations are subject to cyber-attacks or other cyber incidents that could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.
We rely heavily on digital technologies and services. We use these technologies for internal purposes, including data storage (which may include personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders), processing, and transmissions, as well as in our interactions with customers and suppliers. Digital technologies are subject to the risk of cyber-attacks, security breaches and other cyber incidents, which could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial-of-service attacks and other attacks and similar disruptions from the unauthorized use of or access to computer systems. If our systems for protecting against cybersecurity risks prove not to be sufficient, we could be adversely affected by, among other things: loss of or damage to intellectual property, proprietary or confidential information, or customer, supplier, or employee data; interruption of our business operations; and increased costs required to prevent, respond to, or mitigate cybersecurity attacks. These risks could harm our reputation and our relationships with customers, suppliers, employees, and other third-parties, and may result in claims against us, including liability under laws that protect the privacy of personal information. In addition, these risks could have a material adverse effect on our business, results of operations and financial condition.
Adoption of fresh start accounting beginning in the first quarter of 2017 limits the comparability of our current and future financial condition and results of operations to our financial condition and results of operations for periods prior to our emergence from the Chapter 11 Proceeding.
Upon our emergence from the Chapter 11 Proceeding, we adopted fresh start accounting in accordance with the provisions set forth in Accounting Standards Codification Topic 852 - Reorganizations. Our consolidated financial statements also reflect all of the transactions contemplated by the Restructuring Plan. Accordingly, our financial condition and results of operations subsequent to emergence are not comparable to the financial condition or results of operations reflected in our historical financial statements prior to emergence.
More stringent trucking regulations may increase our costs and negatively impact our results of operations.
As part of the services we provide, we operate as a motor carrier and therefore are subject to regulation by the DOT, and by other various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. In addition, the trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, require onboard black box recorder devices or limits on vehicle weight and size. For example, in December 2016, the DOT finalized minimum training standards for new drivers seeking a commercial driver’s license. Certain motor vehicle operators are required to register with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety

27


performance criteria, and a revocation could result in a suspension of operations. Since 2010, the DOT has pursued its Compliance, Safety, Accountability (“CSA”) program, in an effort to improve commercial truck and bus safety. A component of CSA is the Safety Measurement System (“SMS”), which analyzes all safety violations recorded by federal and state law enforcement personnel to determine a carrier’s safety performance. The SMS is intended to allow DOT to identify carriers with safety issues and intervene to address those problems.
Interstate motor carrier operations are subject to safety requirements prescribed by the DOT. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar foreign anti-bribery laws.
The United States Foreign Corrupt Practices Act (the “FCPA”) and similar worldwide anti-bribery laws generally prohibit companies and their intermediaries and partners from making, offering or authorizing improper payments to non-U.S. government officials for the purpose of obtaining or retaining business. Although we currently have no international operations, we previously did business and may do business in the future in countries or regions where strict compliance with anti-bribery laws may conflict with local customs and practices. Our employees, intermediaries, and partners may face, directly or indirectly, corrupt demands by government officials, political parties and officials, tribal or insurgent organizations, or private entities in the countries in which we operate or may operate in the future. As a result, we face the risk that an unauthorized payment or offer of payment could be made by one of our employees, intermediaries, or partners even if such parties are not always subject to our control or are not themselves subject to the FCPA or other anti-bribery laws to which we may be subject. We are committed to doing business in accordance with applicable anti-bribery laws and have implemented policies and procedures concerning compliance with such laws. Our existing safeguards and any future improvements, however, may prove to be less than effective, and our employees, intermediaries, and partners may engage in conduct for which we might be held responsible. Violations of the FCPA and other anti-bribery laws (either due to our acts, the acts of our intermediaries or partners, or our inadvertence) may result in criminal and civil sanctions and could subject us to other liabilities in the U.S. and elsewhere. Even allegations of such violations could disrupt our business and result in a material adverse effect on our business and operations.
Risks Related to Our Common Stock
The concentration of our capital stock ownership among our largest stockholders and their affiliates will limit your ability to influence corporate matters.
A large percentage of our shares of common stock are held by a relatively small number of investors whose interests may conflict. Consequently, these holders (each of whom we refer to as a “principal stockholder”) may have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership and the rights of our principal stockholders will limit your ability to influence corporate matters and, as a result, actions may be taken that you may not view as beneficial.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and our principal stockholders and their respective affiliates, including portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Several of our principal stockholders are private equity firms or investment funds in the business of making investments in entities in a variety of industries. As a result, our principal stockholders’ existing and future portfolio companies may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.
Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to

28


presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated and, as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor.
Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.
Our Amended and Restated Certificate of Incorporation authorizes us to issue 1,000,000,000 shares of common stock, of which an estimated 66,062,430 shares were outstanding as of February 22, 2019. This number includes 55,463,903 shares issued in connection with our emergence from bankruptcy. We also have 8,046,021 shares of common stock authorized for issuance as equity awards under the 2017 C&J Energy Services, Inc. Management Incentive Plan, of which 351,306 shares are issuable pursuant to outstanding options, 941,341 shares are issuable pursuant to our outstanding restricted share units, 607,715 shares are issuable pursuant to outstanding restricted stock awards and 396,455 shares are issuable pursuant to outstanding performance shares. In addition, as of February 22, 2019, warrants to purchase up to 3,528,027 shares of our common stock were outstanding and immediately exercisable. Shares issued upon exercise of these warrants will generally be freely transferable without restriction or registration under the Securities Act pursuant to Section 1145 of the Bankruptcy Code.
A large percentage of our shares of common stock are held by a relatively small number of investors. We entered into a registration rights agreement (the “Registration Rights Agreement”) with certain of those investors in connection with our emergence from the Chapter 11 Proceeding pursuant to which we have filed a registration statement with the SEC to facilitate potential future sales of such shares by them. In addition, we filed a registration statement with the SEC following the closing of the O-Tex Transaction to register for sale the shares of Specified C&J Common Stock issued to the Stockholders pursuant to the Merger Agreement. Sales of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur, could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.
We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and investments. If any such acquisition or investment is significant, the number of shares of our common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. We may also grant registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and investments.
We cannot predict the effect that future sales of our common stock will have on the price at which our common stock trades or the size of future issuances of our common stock or the effect, if any, that future issuances will have on the market price of our common stock. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the trading price of our common stock.
We have outstanding warrants that are exercisable for shares of common stock of the Company. The exercise of such equity instruments would have a dilutive effect to stockholders of the Company.
On January 6, 2017, we issued 1,180,083 warrants that are exercisable into shares of common stock of the Company at an initial exercise price of $27.95 per warrant. In addition, on July 26, 2017, we issued an additional 2,360,166 warrants with the same terms pursuant to the Warrant Agreement. The exercise of these warrants into common stock would have a dilutive effect to the holdings of our existing stockholders. As of February 22, 2019, warrants to purchase up to 3,528,027 shares of our common stock were outstanding and immediately exercisable. Shares issued upon exercise of these warrants will generally be freely transferable without restriction or registration under the Securities Act pursuant to Section 1145 of the Bankruptcy Code. The warrants will not expire until January 6, 2024 and may create an overhang on the market for, and have a negative effect on the market price of, our common stock.
There is no guarantee that outstanding warrants will continue to be in the money, and unexercised warrants may expire worthless. Further, the terms of such warrants may be amended.
If our stock price is below $27.95 per share, the warrants will have limited economic value, and they may expire worthless. In addition, the warrant agreement provides that the terms of the warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision but requires the approval by the holders of at least a certain percentage of the then-outstanding warrants originally issued to make any change that adversely affects the interests of the holders. Accordingly, we may amend the terms of the warrants in a manner adverse to a holder if holders of at least a certain percentage of the then outstanding warrants approve of such amendment.

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 Because we currently have no plans to pay regular dividends on our common stock for the foreseeable future, you may not receive any return on your investment unless you sell your common stock for a price greater than that which you paid for it.
We have no plans to pay regular dividends on our common stock. Any declaration and payment of future dividends to holders of our common stock is limited by restrictive covenants in our Credit Facility and will be at the sole discretion of our Board and will depend on many factors, including our financial condition, earnings, capital requirements, level of indebtedness, cash flows, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board deems relevant. In addition, any agreements governing our future indebtedness may restrict our ability to pay dividends on our common stock. As a result, you may not receive any return on your investment unless you sell your common stock for a price greater than that which you paid for it.
Certain provisions of our Certificate of Incorporation, Bylaws, Stockholders Agreement and our stockholder rights plan may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our Certificate of Incorporation and our Bylaws may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Certificate of Incorporation and our Bylaws include, among other things, those that:
classify the Board;
limit removal of directors;
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings;
prohibit cumulative voting;
prohibit action by written consent; and
provide that only the Board may call special meetings of stockholders.
These provisions may prevent or discourage attempts to remove and replace incumbent directors. These provisions may also 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, which is responsible for appointing the members of our management.
We may issue preferred stock on terms that could adversely affect the voting power or value of our common stock.
Our Certificate of Incorporation authorizes our Board 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 the Board may determine. The terms of one or more classes or series of preferred stock could adversely affect 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 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 the common stock.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
We lease office space for our principal executive headquarters, which is located at 3990 Rogerdale Rd., Houston, Texas 77042, and for our research and technology facility at 10771 Westpark Dr., Houston, Texas 77042. We also own property for our maintenance facility at 1214 Gas Plant Rd., San Angelo, Texas 76904. In addition, we own or lease numerous other smaller facilities and administrative offices across the geographic regions in which we operate to support our ongoing operations, including district offices, local sales offices, yard facilities and temporary facilities to house employees in regions where infrastructure is limited. We do not believe that any one of these facilities is individually material to our operations. Our leased properties are subject to various lease terms and expirations.

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We believe all properties that we currently occupy are suitable for their intended uses. We believe that our current facilities are sufficient to conduct our operations. However, we continue to evaluate the purchase or lease of additional properties or the consolidation of our properties, as our business requires.
Item 3. Legal Proceedings
We are subject to various legal proceedings and claims incidental to or arising in the ordinary course of our business. Our management does not expect the outcome in any of these known legal proceedings, individually or collectively, to have a material adverse effect on our consolidated financial condition or results of operations.
U.S. Department of Justice Criminal Investigation into Pre-Nabors Merger Incident
There is a pending criminal investigation led by the Department of Justice in connection with a fatality that occurred at a facility we now own in Williston, North Dakota. The fatality occurred on October 3, 2014, prior to our acquisition of such facility and the ongoing business in connection with the Nabors Merger. We are cooperating fully with the investigation and expect to continue to do so. At this time, we cannot predict the outcome of the investigation.
Item 4. Mine Safety Disclosures
Not applicable.

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PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters
Our common stock is traded on the NYSE under the symbol “CJ.” As of February 22, 2019, we had 66,062,430 shares of common stock issued and outstanding, held by approximately 12 registered holders. The number of registered holders does not include holders that have common stock held for them in “street name,” meaning that the stock is held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that hold such stock in “street name” are not.
On February 22, 2019, the last reported sales price of our common stock on the NYSE was $17.62 per share.
We have not declared or paid any cash dividends on our common stock, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. Payments of dividends, if any, will be at the discretion of our Board and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our Board. Additionally, covenants contained in our Credit Facility restrict the payment of cash dividends on our common stock. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Description of our Credit Agreement” in this Annual Report.
Recent Sales of Unregistered Securities
No equity securities of the Company were sold during the period covered by this report that were not registered under the Securities Act.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Repurchases of Equity Securities
The following table summarizes stock repurchase activity for the three months ended December 31, 2018 (in thousands, except average price paid per share).
Period
 
Total Number
of Shares
Purchased
 
Average
Price
Paid Per
Share
 
Total Number of Shares Purchased as Part of Publicly Announced Program
 
Maximum Number (or approximate dollar value) of Shares that may yet be Purchased Under Such Program (a)
October 1—October 31
 
3 (b)

 
$
18.06

 

 
$
129,669

November 1—November 30
 

 
$

 

 
$
129,669

December 1—December 31
 
1,490 (c)

 
$
13.88

 
1,445

 
$
109,650

(a) On July 31, 2018, the Company’s Board of Directors approved a stock repurchase program authorizing the repurchase of up to $150.0 million of the Company’s common stock, inclusive of commissions, over a twelve month period starting August 1, 2018. Repurchases may commence or be suspended at any time without notice. The program does not obligate the Company to purchase a specified number of shares of common stock during the period or at all, and may be modified or suspended at any time at the Company’s discretion. No assurance can be given that shares will be repurchased in the future.
(b) Represents shares that were withheld by us to satisfy tax withholding obligations of employees that arose upon the vesting of restricted shares. The value of such shares is based on the closing price of our common shares on the vesting date.
(c) Includes 45,278 shares that were withheld by us to satisfy tax withholding obligations of employees that arose upon the vesting of restricted shares. The value of such shares is based on the closing price of our common shares on the vesting date.

32


Item 6. Selected Financial Data
This section presents our selected consolidated financial data for the periods and as of the dates indicated. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. The following selected consolidated financial data should be read in conjunction with both Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report in order to understand those factors, such as the Nabors Merger, which may affect the comparability of the Selected Financial Data:
 
 
Successor
 
 
Predecessor
 
 
(In thousands except per share amounts)
 
 
Years Ended December 31,
 
 
2018
 
2017
 
 
2016
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
$
2,222,089

 
$
1,638,739

 
 
$
971,142

 
$
1,748,889

 
$
1,607,944

Net income (loss)
 
$
(130,005
)
 
$
22,457

 
 
$
(944,289
)
 
$
(872,542
)
 
$
68,823

Net income (loss) per common share
 
 
 
 
 
 
 
 
 
 
 
Basic
 
$
(1.94
)
 
$
0.37

 
 
$
(7.98
)
 
$
(8.48
)
 
$
1.28

Diluted
 
$
(1.94
)
 
$
0.37

 
 
$
(7.98
)
 
$
(8.48
)
 
$
1.22

Total assets
 
$
1,424,454

 
$
1,608,857

 
 
$
1,361,682

 
$
2,198,991

 
$
1,612,746

Long-term debt and capital lease obligations, excluding current portion
 
$

 
$

 
 
$

 
$
1,108,123

 
$
349,875


33



ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with the audited consolidated financial statements and the related notes thereto included elsewhere in this Annual Report. This discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in any forward-looking statement because of various factors, including, without limitation, those described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors” of this Annual Report.
Business Overview
C&J Energy Services, Inc., a Delaware corporation (the “Successor” and together with its consolidated subsidiaries for periods subsequent to the Plan Effective Date, “C&J” “we”, “our” or the “Company”) is a leading provider of well construction, intervention, completion, support and other complementary oilfield services and technologies. We provide our services to oil and gas exploration and production companies throughout the continental United States. We are a new well focused provider offering a diverse suite of services throughout the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, rig services, fluids management and other completion and well support services. Based on internal estimates and publicly available data, we believe we are a market leader across most of our service lines, and our goal is to be the top service provider and a market leader for the U.S. land markets across all of our service lines. We are headquartered in Houston, Texas and operate across all active onshore basins in the continental United States.
Demand for our services, and therefore our operating and financial performance, is heavily influenced by drilling, completion and production activity by our customers, which is significantly impacted by commodity prices. Due to a severe industry downturn, the Predecessor Companies voluntarily filed petitions for reorganization seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code in 2016. We emerged in 2017 from the Chapter 11 Proceeding as the market was beginning to recover. See Part I, Item 1 “Business” of this Annual Report for an overview of our history, including additional information on our predecessor's bankruptcy filing, and business environment.
Operating Overview & Strategy
Our revenues and profits are generated by providing services and equipment to customers who operate oil and gas properties and invest capital to drill new wells and enhance production or perform maintenance on existing wells. Our results of operations in our core service lines are driven primarily by five interrelated, fluctuating variables: (1) the drilling, completion and production activities of our customers, which is primarily driven by oil and natural gas prices and directly affects the demand for our services; (2) the price we are able to charge for our services and equipment, which is primarily driven by the level of demand for our services and the supply of equipment capacity in the market; (3) the cost of materials, supplies and labor involved in providing our services, and our ability to pass those costs on to our customers; (4) our activity, or “utilization” levels; and (5) the quality, safety and efficiency of our service execution.
Our operating strategy is focused on maintaining high asset utilization levels to maximize revenue generation while controlling costs to gain a competitive advantage and drive returns. We believe that the quality and efficiency of our service execution and aligning with customers who recognize the value that we provide through service quality and efficiency gains are central to our efforts to support utilization and grow our business. For additional information about how each of our business segments measure asset utilization, please see “Our Reportable Segments and Strategy” in Part I, Item 1 “Business.”
However, asset utilization cannot be relied on as wholly indicative of our financial or operating performance due to variations in revenue and profitability from job to job, the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed. Given the volatile and cyclical nature of activity drivers in the U.S. onshore oilfield services industry, coupled with the varying prices we are able to charge for our services and the cost of providing those services, among other factors, operating margins can fluctuate widely depending on supply and demand at a given point in the cycle.
Historically, our utilization levels have been highly correlated to U.S. onshore spending by our customers, which is heavily driven by the price of oil and natural gas. Generally, as capital spending by our customers increases, drilling, completion and production activity also increases, resulting in increased demand for our services, and therefore more days or hours worked (as the case may be). Conversely, when drilling, completion and production activity levels decline due to lower spending by our customers, we generally provide fewer services, which results in fewer days or hours worked (as the case may

34



be). Additionally, during periods of decreased spending by our customers, we may be required to discount our rates or provide other pricing concessions to remain competitive and support utilization, which negatively impacts our revenue and operating margins. During periods of pricing weakness for our services, we may not be able to reduce our costs accordingly, and our ability to achieve any cost reductions from our suppliers typically lags behind the decline in pricing for our services, which could further adversely affect our results. Furthermore, when demand for our services increases following a period of low demand, our ability to capitalize on such increased demand may be delayed while we reengage and redeploy equipment and crews that have been idled during a downturn. The mix of customers that we are working for, as well as our exposure to the spot market, also impacts our utilization. For additional information about factors impacting our business and results of operations, please see “Industry Trends and Outlook” in this Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
To help manage asset utilization and profitability in our operations, our management monitors revenue, Adjusted EBITDA by reportable segment and certain operational data indicative of utilization levels, which information is provided for each of our operating segments under “Reportable Segments” in this Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Management evaluates the financial performance of our reportable segments primarily based on each segment's Adjusted EBITDA because management believes Adjusted EBITDA provides important information about the activity and profitability of our lines of business within each reportable segment and aids us in analytical comparisons for purposes of, among other things, efficiently allocating our assets and resources. Adjusted EBITDA at the segment level is not considered to be a non-GAAP financial measure as it is our segment measure of profit or loss and is required to be disclosed under GAAP pursuant to ASC 280. Please read Note 7 - Segment Information in Part II, Item 8 “Financial Statements” of this Annual Report, for the definition and calculation of Adjusted EBITDA.
Results of Operations
The following is a comparison of our results of operations for the year ended December 31, 2018, compared to the year ended December 31, 2017, and a comparison of our results of operations for the year ended December 31, 2017, compared to the year ended December 31, 2016. The results for the Predecessor on January 1, 2017 reflect solely the impact of the application of fresh start accounting on that date and are therefore not included in the discussion of results of operations below.

35



Results for the Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
The following table summarizes the change in our results of operations for the year ended December 31, 2018, compared to the year ended December 31, 2017:
 
 
Years Ended December 31,
 
 
2018
 
2017
 
$ Change
 
 
(In thousands)
Completion Services:
 
 
 
 
 
 
     Revenue
 
$
1,453,577

 
$
1,107,014

 
$
346,563

     Operating income (loss)
 
$
124,451

 
$
132,889

 
$
(8,438
)
 
 
 
 
 
 
 
Well Construction and Intervention Services:
 
 
 
 
 
 
     Revenue
 
$
375,667

 
$
149,497

 
$
226,170

     Operating income (loss)
 
$
(120,780
)
 
$
5,267

 
$
(126,047
)
 
 
 
 
 
 
 
Well Support Services:
 
 
 
 
 
 
     Revenue
 
$
392,845

 
$
382,228

 
$
10,617

     Operating loss
 
$
(22,197
)
 
$
(22,334
)
 
$
137

 
 
 
 
 
 
 
Corporate / Elimination:
 
 
 
 
 
 
     Operating loss
 
$
(112,447
)
 
$
(131,601
)
 
$
19,154

 
 
 
 
 
 
 
Combined:
 
 
 
 
 
 
     Revenue
 
$
2,222,089

 
$
1,638,739

 
$
583,350

 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
Direct costs
 
1,724,707

 
1,288,092

 
436,615

Selling, general and administrative expenses
 
225,511

 
250,871

 
(25,360
)
Research and development
 
6,286

 
6,368

 
(82
)
Depreciation and amortization
 
224,867

 
140,650

 
84,217

Impairment Expense
 
146,015

 

 
146,015

(Gain) loss on disposal of assets
 
25,676

 
(31,463
)
 
57,139

Operating loss
 
(130,973
)
 
(15,779
)
 
(115,194
)
Other income (expense):
 
 
 
 
 
 
Interest expense, net
 
(3,899
)
 
(1,527
)
 
(2,372
)
Other income (expense), net
 
2,453

 
3

 
2,450

Total other expenses, net
 
(1,446
)
 
(1,524
)
 
78

Loss before income taxes
 
(132,419
)
 
(17,303
)
 
(115,116
)
Income tax benefit
 
(2,414
)
 
(39,760
)
 
37,346

Net income (loss)
 
$
(130,005
)
 
$
22,457

 
$
(152,462
)

Revenue
Revenue increased $583.4 million, or 35.6%, to $2.2 billion for the year ended December 31, 2018, as compared to $1.6 billion for the year ended December 31, 2017. The increase in revenue was primarily due to (i) an increase of $346.6 million of revenue in our Completion Services segment primarily as a result of our expanded fracturing services asset base, (ii) an increase of $226.2 million in our Well Construction and Intervention Services ("WC&I") segment primarily as a result of our expanded cementing business with the O-Tex Transaction during the fourth quarter of 2017 and (iii) an increase of $10.6 million in our Well Support Services segment primarily as a result of improving utilization and pricing levels, partially offset by the divestiture of our Canadian rig services business in the fourth quarter of 2017.

36



Direct Costs
Direct costs increased $436.6 million, or 33.9%, to $1.7 billion for the year ended December 31, 2018, as compared to $1.3 billion for the year ended December 31, 2017. The increase in direct costs was primarily due to the operations of our expanded asset bases and improved utilization which resulted in additional labor and consumable costs, as well as our expanded cementing business with the acquisition of O-Tex.
As a percentage of revenue, direct costs decreased to 77.6% for the year ended December 31, 2018, as compared to 78.6% for the year ended December 31, 2017. The decrease was primarily due to improved pricing for our services due to the more favorable market conditions as well as the divestiture of underperforming businesses and shutting down unprofitable districts.
Selling, General and Administrative Expenses ("SG&A") and Research and Development Expenses ("R&D")
SG&A decreased $25.4 million, or 10.1%, to $225.5 million for the year ended December 31, 2018, as compared to $250.9 million for the year ended December 31, 2017. The decrease in SG&A was primarily due to (i) an $11.2 million reduction in employee related costs (excluding O-Tex), (ii) a $10.8 million reduction in share-based compensation expense related to an accelerated vesting in the first quarter of 2017, (iii) a $7.9 million reduction in restructuring charges related to our Chapter 11 bankruptcy proceeding in the corresponding prior year period, (iv) a $3.6 million reduction in acquisition-related costs related to the O-Tex Transaction and (v) a $1.9 million reduction in legal expenses, offset by (i) an incremental $10.1 million increase in SG&A expenses as a result of the acquisition of O-Tex and (ii) a $4.2 million increase in severance expense and accelerated equity vesting associated with the departure of an executive officer.
Depreciation and Amortization Expense ("D&A")
D&A increased $84.2 million, or 59.9%, to $224.9 million for the year ended December 31, 2018, as compared to $140.7 million for the same period in 2017. The increase in D&A was primarily the result of increased capital expenditures associated with equipment placed into service during 2018 as well as the integration of the acquired O-Tex assets in the fourth quarter of 2017.
Impairment Expense
During the fourth quarter of 2018, a significant decline in our share price, which resulted in our market capitalization dropping below our book value of equity, as well as an overall decrease in commodity prices were deemed triggering events that led to a test for goodwill impairment. Based on the results of the test, we recorded impairment expense of $146.0 million for the year ended December 31, 2018, consisting of all of the goodwill associated with our WC&I reporting unit.
Gain (loss) on disposal of assets
Loss on disposal of assets increased $57.1 million, or 181.6% to $25.7 million for the year ended December 31, 2018, as compared to a gain of $31.5 million for the same period in 2017. The increase is primarily related to a charge of $21.4 million in 2018, in connection with the retirement of certain assets, primarily within the fracturing, coiled tubing and well support services asset groups, that were deemed to be obsolete with unfavorable economics for refurbishment based on prevailing customer preferences and current market conditions. During 2017, the $31.5 million gain on disposal of assets was primarily related to the sale of assets associated with our Canadian rig services business and the sale of our equipment manufacturing and repair business.
Income Taxes
We recorded an income tax benefit of $2.4 million for the year ended December 31, 2018, at an effective rate of 1.8%, compared to an income tax benefit of $39.8 million for the year ended December 31, 2017, at an effective rate of 229.8%. The decrease in the effective tax rate is primarily due to adjustments to maintain a full valuation allowance in 2018, compared with a partial release of valuation allowance in 2017, which provided the additional income tax benefit. In addition, in 2018, due to U.S. Tax Reform, we netted indefinite-lived deferred tax liabilities with certain indefinite-lived deferred tax assets, including net operating loss carryforwards generated after January 1, 2018 before applying the valuation allowance.

37



Results for the Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
The following table summarizes the change in our results of operations for the year ended December 31, 2017, compared to the year ended December 31, 2016 (in thousands):
 
 
Years Ended December 31,
 
 
2017
 
2016
 
$ Change
 
 
(In thousands)
Completion Services:
 
 
 
 
 
 
     Revenue
 
$
1,107,014

 
$
515,939

 
$
591,075

     Operating income (loss)
 
$
132,889

 
$
(232,031
)
 
$
364,920

 
 
 
 
 
 
 
Well Construction and Intervention Services:
 
 
 
 
 
 
     Revenue
 
$
149,497

 
$
83,848

 
$
65,649

     Operating income (loss)
 
$
5,267

 
$
(74,583
)
 
$
79,850

 
 
 
 
 
 
 
Well Support Services:
 
 
 
 
 
 
     Revenue
 
$
382,228

 
$
363,768

 
$
18,460

     Operating loss
 
$
(22,334
)
 
$
(377,707
)
 
$
355,373

 
 
 
 
 
 
 
Other Support Services:
 
 
 
 
 
 
     Revenue
 
$

 
$
7,587

 
$
(7,587
)
     Operating loss
 
$

 
$
(51,778
)
 
$
51,778

 
 
 
 
 
 
 
Corporate / Elimination:
 
 
 
 
 
 
     Operating loss
 
$
(131,601
)
 
$
(133,909
)
 
$
2,308

 
 
 
 
 
 
 
Combined:
 
 
 
 
 
 
Revenue
 
$
1,638,739

 
$
971,142

 
$
667,597

Costs and expenses:
 
 
 
 
 
 
Direct costs
 
1,288,092

 
947,255

 
340,837

Selling, general and administrative expenses
 
250,871

 
229,267

 
21,604

Research and development
 
6,368

 
7,718

 
(1,350
)
Depreciation and amortization
 
140,650

 
217,440

 
(76,790
)
Impairment Expense
 


436,395

 
(436,395
)
Gain (loss) on disposal of assets
 
(31,463
)
 
3,075

 
(34,538
)
Operating loss
 
(15,779
)
 
(870,008
)
 
854,229

Other income (expense):
 
 
 
 
 
 
Interest expense, net
 
(1,527
)
 
(157,465
)
 
155,938

Other income (expense), net
 
3

 
9,504

 
(9,501
)
Total other expenses, net
 
(1,524
)
 
(147,961
)
 
146,437

Losses before reorganization items and income taxes
 
(17,303
)
 
(1,017,969
)
 
1,000,666

Reorganization items
 

 
55,330

 
(55,330
)
Income tax expense
 
(39,760
)
 
(129,010
)
 
89,250

Net income (loss)
 
$
22,457

 
$
(944,289
)
 
$
966,746


38



Revenue
Revenue increased $667.6 million, or 68.7%, to $1.6 billion for the year ended December 31, 2017, as compared to $971.1 million for the year ended December 31, 2016. The increase in revenue was primarily due to (i) an increase of $591.1 million in our Completion Services segments a result of the continued strong demand for all of our completion services, which resulted in improved utilization and pricing across our asset base, (ii) an increase of $65.6 million in our WC&I Services segment primarily due to continued strong demand and utilization across our cementing and coiled tubing service lines and (iii) an increase of $18.5 million in our Well Support segment as a result of improvement in both our rig services and special services product lines, offset by a decrease of $7.6 million in our Other Services segment as a result of the segment being divested during the comparable prior year period.
Direct Costs
Direct costs increased $340.8 million, or 36.0%, to $1.3 billion for the year ended December 31, 2017, as compared to $947.3 million for the year ended December 31, 2016. The increase in direct costs was primarily due to the corresponding increase in revenue from our Completion and WC&I Services segments, which resulted in additional labor and consumable costs. Revenue has been positively impacted by overall increased utilization levels across our Completion Services, WC&I Services and Well Support Services segments which resulted from the improved market environment.
As a percentage of revenue, direct costs decreased to 78.6% for the year ended December 31, 2017, as compared to 97.5% for the year ended December 31, 2016. The decrease was primarily due to substantially improved pricing for our services due to the more favorable market conditions resulting from the increase in commodity prices.
Selling, General and Administrative Expenses ("SG&A") and Research and Development Expenses ("R&D")
SG&A increased $21.6 million, or 9.4%, to $250.9 million for the year ended December 31, 2017, as compared to $229.3 million for the year ended December 31, 2016. The increase in SG&A was primarily due to (i) a $40.8 million increase in compensation expense primarily as a result of (a) significant increases in operating performance throughout 2017 and (b) the reinstatement of certain previously reduced compensation programs during the first half of 2017, (ii) a $10.3 million increase in professional fee expense primarily as a result of efficiency initiatives within our finance and human resources departments and (iii) a $3.8 million increase in acquisition-related costs related to the O-Tex acquisition, partially offset by (i) a $19.2 million reduction in costs related to our restructuring activities and Chapter 11 Proceeding during the corresponding prior year period, (ii) a $9.2 million reduction in integration related costs incurred in the corresponding prior year primarily related to the planned implementation of the new ERP system and (iii) a $6.1 million reduction in severance costs as a result of headcount reductions in the corresponding prior year period.
Depreciation and Amortization Expense ("D&A")
D&A decreased $76.8 million, or 35.3%, to $140.7 million for the year ended December 31, 2017, as compared to $217.4 million for the same period in 2016. The decrease in D&A was primarily due to a lower value of the asset base as a result of the estimated fresh start adjustments on the Fresh Start Reporting Date to our property, plant and equipment ("PP&E") and other intangible assets.
Impairment Expense
Due to the severe downturn in the oil and gas industry, and the resulting weakness in demand for our services, we determined that it was necessary to test goodwill for impairment and to test PP&E and other intangible assets for recoverability throughout 2016.
Impairment expense for the year ended December 31, 2016 was $436.4 million, consisting of $314.3 million of goodwill impairment related to impairment of all remaining goodwill associated with our Well Support Services segment, along with $61.0 million related to other intangible assets and $61.1 million related to PP&E within each of our Completion Services, Well Support Services, and Other Services segments.
Gain (loss) on disposal of assets
Gain on disposal of assets increased $34.5 million to $31.5 million for the year ended December 31, 2017, as compared to a loss of $3.1 million for the same period in 2016. The increase is related to a $31.5 million gain on disposal of

39



assets during 2017, which was primarily related to the sale of assets associated with its Canadian rig services business and its divested equipment manufacturing and repair business.
Reorganization items
Reorganization items of $55.3 million for the year ended December 31, 2016 are primarily related to professional fees of $41.2 million, contract termination settlements of $20.3 million and revisions of estimated claims of $0.8 million, partially offset by $5.2 million in related party settlements and $1.8 million in vendor claims adjustments in connection with our Chapter 11 Proceeding.
Interest Expense, net
Interest expense decreased $155.9 million, or 99.0%, to $1.5 million for the year ended December 31, 2017 from $157.5 million for the year ended December 31, 2016. The decrease is primarily due to the settlement of all outstanding borrowings of the Predecessor in accordance with the Restructuring Plan in addition to the prior year $91.9 million of accelerated amortization of original issue discount and deferred financing costs as a result of the Restructuring Support agreement.
Income Taxes
We recorded an income tax benefit of $39.8 million for the year ended December 31, 2017, at an effective rate of 229.8%, compared to income tax benefit of $129.0 million for the year ended December 31, 2016, at an effective rate of 12.0%. The increase in the effective tax rate is primarily due to adjustments to reduce valuation allowances previously applied against certain deferred tax assets, including net operating loss carryforwards. These adjustments were the result of the treatment of the O-Tex Transaction as a non-taxable transaction, resulting in the acquired assets and liabilities having carryover basis for tax purposes. At the closing of the transaction, an estimated deferred tax liability of approximately $31.3 million was recorded to account for the differences between the preliminary purchase price allocation and carryover tax basis.
Our Reportable Segments
As of December 31, 2018, our reportable segments were:
Completion Services, which consists of the following businesses and service lines: (1) fracturing services; (2) cased-hole wireline and pumping services; and (3) completion support services, which includes our R&T department.
Well Construction and Intervention Services, which consists of the following businesses and service lines: (1) cementing services and (2) coiled tubing services.
Well Support Services, which consists of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) other specialty well site services.
During the first quarter of 2018, we decided to exit our directional drilling business and artificial lift business. We are in the process of divesting the assets and inventory associated with our directional drilling operations. We completed the sale of substantially all of the assets and inventory associated with the artificial lift business on July 2, 2018.
Our reportable segments are described in more detail below; for financial information about our reportable segments, including revenue from external customers and total assets by reportable segment, please see “Note 11 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.
Completion Services
The core services provided through our Completion Services segment are fracturing, cased-hole wireline and pumping services. Our completion support services are focused on supporting the efficiency, reliability and quality of our operations. Our R&T department provides in-house manufacturing capabilities that help to reduce operating cost and enable us to offer more technologically advanced and efficiency focused completion services, which we believe is a competitive differentiator. For example, through our R&T department we manufacture the data control instruments used in our fracturing operations and the perforating guns and addressable switches used in our wireline operations; these products are also available for sale to third-parties. The majority of revenue for this segment is generated by our fracturing business.

40



During the fourth quarter of 2018, our fracturing business deployed, on average, approximately 650,000 hydraulic horsepower (“HHP”) out of our fleet of approximately 860,000 HHP as of December 31, 2018. We exited the year with approximately 695,000 HHP deployed, consisting of sixteen horizontal and two vertical fleets. Our typical horizontal fleet size consists of 20 pumps, or approximately 40,000 HHP, and our typical vertical fleet size consists of 10 pumps, or approximately 20,000 HHP. In our cased-hole wireline and pumping business, during the fourth quarter of 2018, we deployed, on average, approximately 70 wireline trucks and 81 pumpdown units. Not all of our deployed assets are utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.
Revenue and profitability for the fourth quarter of 2018 decreased year-over-year and sequentially in our Completion Services segment due to customer budget exhaustion and lower utilization levels. Due to soft market conditions, we temporarily idled two horizontal equivalent fleets early in the fourth quarter. We focused on reallocating fleets on a dedicated basis to large, efficient customers and these two fleets were re-deployed to dedicated customers in early December, and we exited the fourth quarter at our third quarter exit rate of 695,000 HHP deployed.  In our wireline and pumping businesses, lower customer activity levels from budget exhaustion, year-end seasonality and weather-driven delays resulted in both revenue and profitability for the fourth quarter of 2018 decreasing year-over-year and sequentially.
For the year ended December 31, 2018, revenue from our Completion Services segment was $1.5 billion, representing approximately 65.4% of our total revenue, compared with revenue of $1.1 billion for the year ended December 31, 2017, which represents a 31.3% year-over-year increase. Adjusted EBITDA from this segment for the year ended December 31, 2018 was $274.3 million, compared with $200.9 million of Adjusted EBITDA for the year ended December 31, 2017, which represents a 36.5% year-over-year increase.
 
Years Ended December 31,
 
2018
 
2017
 
(In thousands)
Revenue
 
 
 
Fracturing
$
1,002,664

 
$
777,147

Cased-hole Wireline & Pumping
420,708

 
315,999

Other
30,205

 
13,868

Total revenue
$
1,453,577

 
$
1,107,014

 
 
 
 
Adjusted EBITDA
$
274,261

 
$
200,936

 
 
 
 
Average active hydraulic fracturing horsepower
670,000

 
515,000

Total fracturing stages
18,544

 
15,189

 
 
 
 
Average active wireline trucks
69

 
72

 
 
 
 
Average active pumpdown units
78

 
61

Please see Note 11 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report, for the definition and calculation of Adjusted EBITDA.
Well Construction and Intervention Services
The core services provided through our Well Construction and Intervention Services segment are cementing and coiled tubing services. Although we previously provided directional drilling services through this segment, we ceased those operations during the first quarter of 2018, and we are in the process of selling the related assets and inventory. The majority of revenue for this segment is generated by our cementing business. During the fourth quarter of 2018, our cementing business deployed, on average, approximately 69 cementing units and in our coiled tubing business, we deployed, on average, approximately 17 coiled tubing units during the quarter. Our deployed assets may not be utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.
The deployment of additional assets and the acquisition of O-Tex caused both fourth quarter revenue and profitability in our Well Construction and Intervention Services segment to increase year-over-year; however, fourth quarter revenue and profitability decreased sequentially mostly due to customer budget exhaustion and year-end seasonality. These

41



conditions particularly impacted our cementing business, and we experienced unexpected customer shutdowns. On average, all of our large diameter coiled tubing units were deployed throughout the quarter, but overall activity levels decreased due to higher levels of year-end seasonality and an unfavorable job mix as completion-driven activity levels slowed at year-end.
For the year ended December 31, 2018, revenue from our Well Construction and Intervention Services segment was $375.7 million, representing approximately 16.9% of our total revenue, compared with revenue of $149.5 million for the year ended December 31, 2017, which represents a 151.3% year-over-year increase. Adjusted EBITDA from this segment for the year ended December 31, 2018 was $68.5 million, compared with $21.0 million of Adjusted EBITDA for the year ended December 31, 2017, which represents a 226.7% year-over-year increase.
 
Years Ended December 31,
 
2018
 
2017
 
(In thousands)
Revenue
 
 
 
  Cementing
$
260,969

 
$
69,447

  Coiled Tubing
114,617

 
78,138

  Other
81

 
1,912

Total revenue
$
375,667

 
$
149,497

 
 
 
 
Adjusted EBITDA
$
68,452

 
$
20,952

 
 
 
 
Average active cementing units
71

 
33

 
 
 
 
Average active coiled tubing units
17

 
19

Please read Note 11 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report, for additional information about segment Adjusted EBITDA.
Well Support Services
Our Well Support Services segment focuses on post-completion activities at the well site, including rig services, such as workover and plug and abandonment, fluids management services, and other specialty well site services. Although we previously provided artificial lift applications through this segment, we completed the sale of substantially all of the assets and inventory associated with this business on July 2, 2018. Additionally, in 2017 and 2018 in response to the highly competitive landscape and reflecting our returns-focused strategy, we have continued to focus on operational rightsizing measures to better align these businesses with current market conditions. This strategy has resulted in closing facilities and idling unproductive equipment. For example, we divested our Canadian rig services business during the fourth quarter of 2017, we exited the condensate hauling business in South Texas during the first quarter of 2018, and we shut-down our East Texas rig services operations late in the second quarter of 2018. The majority of revenue for this segment is generated by our rig services business, and we consider rig services and fluids management to be the core businesses within this segment.
During the fourth quarter of 2018, our rig services business deployed, on average, approximately 123 workover rigs per workday out of our average fleet of approximately 344 marketable workover rigs. In our fluids management business, we deployed, on average, approximately 645 fluid services trucks per workday and approximately 1,403 frac tanks per workday. In our fluids management business, we own 23 private salt water disposal wells for fluids disposal purposes. However, our deployed assets may not be utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.
Segment revenue and profitability for the fourth quarter increased both year-over-year and sequentially due to the deployment of additional assets in the U.S. and higher overall pricing for our services. The prior year period contained partial results from our Canadian rig services business that we divested in early November 2017, which diluted the 2018 year-over-year operating results improvement.  In our rig services business, we deployed additional workover rigs into our core operating basins of California and West Texas, and we exited the fourth quarter with our highest deployed workover rig count of 2018.  These improved results were partially offset by higher levels of year-end seasonality and select unexpected customer shutdowns in several of our core operating basins, especially in the Bakken and the Rocky Mountain regions.  Special services revenue and profitability remained strong primarily due to increased fishing and rental activity in select basins.  Our fluids management business benefited from the full implementation of several contract wins in the third quarter of 2018 for California operations,

42



which was partially offset by lower activity levels in South Texas due to unexpected downtime at certain saltwater disposal wells.
For the year ended December 31, 2018, revenue from our Well Support Services segment was $392.8 million, representing approximately 17.7% of our total revenue, compared with revenue of $382.2 million for the year ended December 31, 2017, which represents a 2.8% year-over-year increase. Adjusted EBITDA from this segment for the year ended December 31, 2018 was $39.7 million, compared with $9.2 million of Adjusted EBITDA for the year ended December 31, 2017, which represents a 329.8% year-over-year increase.
 
Years Ended December 31,
 
2018
 
2017
 
(In thousands)
Revenue
 
 
 
  Rig Services
$
209,708

 
$
218,819

  Fluids Management Services
137,200

 
122,949

  Other Special Well Site Services
45,937

 
40,460

Total revenue
$
392,845

 
$
382,228

 
 
 
 
Adjusted EBITDA
$
39,686

 
$
9,233

 
 
 
 
Average active workover rigs
145

 
188

Total workover rig hours
374,444

 
452,948

 
 
 
 
Average active fluids management trucks
634

 
638

Total fluids management truck hours
1,259,254

 
1,281,024

Please read Note 11 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report, for additional information about segment Adjusted EBITDA.
Industry Trends and Outlook
We face many challenges and risks in the industry in which we operate. Although many factors contributing to these risks are beyond our ability to control, we continuously monitor these risks and have taken steps to mitigate them to the extent practicable. In addition, while we believe that we are well positioned to capitalize on available growth opportunities, we may not be able to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read the factors described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” in Part I, Item 1A of this Annual Report for additional information about the known material risks that we face.
General Industry Trends
The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by oil and gas companies to their drilling, completion and workover budgets. The oil and gas industry is also impacted by geopolitical factors, such as general domestic and international economic conditions, the actions of the OPEC oil cartel, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity, weather conditions in the U.S., and other factors that are beyond our control.
Demand for our services tends to be volatile because it is a direct function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the United States. Our customers’ willingness to undertake such activities and make such expenditures depends largely upon prevailing industry conditions, which are influenced by numerous factors that are beyond our control, including, among others, those described above. The current and projected prices of oil, natural gas and natural gas liquids are important catalysts for customer activity levels. Perceived instability or weakness in oil and natural gas prices influences our customers to pause activity, curtail their operations, reduce their expenditures, and request pricing concessions to reduce their operating costs. In a lower oil and gas

43



price environment, demand for service and maintenance generally decreases as oil and gas producers decrease their activity and operating and capital expenditures. Because the type of services that we offer can be easily “started” and “stopped,” and oil and gas producers generally tend to be less risk tolerant 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. Given the significant influence of oil and gas prices, customer activity levels historically have been, and are expected to continue to be, highly volatile. A prolonged low level of customer activity could adversely affect our financial condition and results of operations.
Competition and Demand for Our Services
Our revenue and profitability are directly affected by changes in utilization and pricing levels for our services, which fluctuate in direct response to changes in the level of drilling, completion and production activity by our customers. Declines in utilization or pricing for our services impact, among other things, our ability to maintain revenue and profitability. During periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results. Furthermore, even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset any rising costs. In an unfavorable pricing environment, we may decide to idle equipment rather than work at unsustainable pricing levels, although we may not be able to fully reduce our costs accordingly. 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 position and results of operations.
We operate in highly competitive areas of the oilfield services industry with significant potential for excess capacity. With respect to all of our core services, the equipment can be moved with relative ease from one region to another in response to changes in customer activities and market conditions, which can result in an oversupply of equipment in high activity areas. Increases in supply relative to demand in our core operating areas and geographic markets could negatively impacted both pricing and utilization for our services and adversely affected our financial results.
See Part I, Item 1 “Business” for additional discussion of the market challenges within our industry.
Current Market Conditions and Outlook
The steady increase in oil prices from July 2017 through early October 2018 created a strong environment that incentivized our customers to increase their drilling and completion programs. During that time period, the price of oil averaged approximately $61.00 per barrel, a level that allowed many of our customers to generate adequate financial returns and incentivized them to increase drilling, completion and production activities in many domestic oil-producing basins. During that time period, the price of natural gas averaged $2.88 per Mcf, a level that has not encouraged a material increase in drilling and completion activities in natural gas focused basins. Our results for 2018 generally reflect our focus on large, efficient customers that have increased activity levels in the most prolific oil-producing basins in the Continental United States.
During the fourth quarter of 2018, the industry continued to experience concerns that growing oil production in West Texas may temporarily exceed the capacity of the region’s pipelines to transport oil from oil wells to oil refineries. We have a significant operating presence in West Texas and our financial results for the fourth quarter of 2018 were negatively impacted by lower activity levels in that basin. Additionally, many of our customers spent more than half of their capital expenditure budget in the first half of 2018, which resulted in higher levels of year-end budget exhaustion that negatively affected most of our businesses in almost all of our operating basins. Also, oil prices declined approximately 40% from a high of just over $76.00 per barrel in early October 2018 to a low of just under $43.00 per barrel in late December 2018, which contributed to higher levels of year-end seasonality and incentivized customers to delay planned expenditure into 2019. The timing of this oil price decline comes as many of our customer are formulating their 2019 capital spending plans, which we expect will have negative implications on activity levels and utilization of deployed equipment in 2019, especially in our new-well completion-oriented businesses.
We continue to monitor the market for our services and the competitive environment. Although the U.S. domestic rig count has increased off the historical low recorded in mid-2016, there are signs the drilling rig count could decline in early 2019 due to weakening oil prices and declining E&P capital expenditures. Additionally, increasing competition, logistical constraints and other factors, such as an oversupply of available equipment and lower overall pricing for our services, represent risks to our near-term financial results and may negatively impact our performance in many of our core businesses in 2019.
We will continue to manage our business in line with demand for our services and make adjustments as necessary to effectively respond to changes in market conditions, customer activity levels, pricing for our services and equipment, and utilization of our equipment and personnel. Our response to the industry's persistent uncertainty is to maintain sufficient

44



liquidity, preserve our conservative capital structure and closely monitor our discretionary spending. We take a measured approach to asset deployment, balancing our view of current and expected customer activity levels with a focus on generating positive returns for our shareholders. Our priorities remain to drive revenue by maximizing utilization, to improve margins through cost controls, to protect and grow our market share by focusing on the quality, safety and efficiency of our service execution, and to ensure that we are strategically positioned to capitalize on constructive market dynamics.
Completion Services Outlook
Our strategy of increasing our dedicated fleet count to large, existing customers should result in higher utilization and better financial performance in our fracturing business during the first quarter of 2019. Additionally, our spot horizontal fleet count has decreased back to lows not seen since the second quarter of 2018, and it is possible that we could have all of our deployed horizontal fleets dedicated by the end of the first quarter of 2019. With that said, the current market conditions remain volatile, and our primary focus remains to lower our overall cost structure and to more closely align with large, dedicated customers with deep inventories of work and proven track records of efficient operations, many of which we have created long-term relationships with over the past several years. In our wireline and pumping businesses, we expect a slow start to the first quarter as many of our customers in the Bakken and the Rocky Mountain regions have indicated they will not commence completion activities until the back half of the first quarter mostly due to inclement weather. We currently expect higher activity levels off year-end seasonal lows in many of our other operating regions such as West Texas and the Mid-Continent, but the expected slow start in the Northwest will offset financial improvement in our other operating basins during the first quarter of 2019.
Well Construction and Intervention Services Outlook
We currently expect that our Well Construction and Intervention Services segment will experience lower activity levels in the first quarter of 2019 primarily due to decreased completion activity and lower overall drilling rig count. Volatile market conditions and select customers releasing drilling rigs will most likely negatively impact our cementing business in the first quarter of 2019. With that said, we will remain focused on controlling costs, maintaining market share and high-grading our customer base by redeploying cementing units with existing customers that plan to maintain stable drilling rig counts in 2019. Despite strong customer demand and improving utilization in West Texas, we believe activity levels will decrease in our coiled tubing business in the first quarter of 2019 primarily due to unfavorable job mix from sluggish improvement in completion-driven activity in both South Texas and the Mid-Continent.
Well Support Services Outlook
We expect improvement in both revenue and profitability in our Well Support Services segment as we continue to benefit from higher activity levels and improved pricing from agreements implemented in late 2018. Additionally, we will continue to focus on deploying more assets with select customers in several of our core operating basins. Increased demand for workover and well maintenance activities should result in higher activity levels throughout the first quarter of 2019, excluding the potential negative impact from inclement weather that typically affects our Well Support Services segment in the first quarter. In our rig services business, we are focused on increasing profitable market share primarily in both California and West Texas due to our reputation of delivering superior service quality and safety and our ability to continue deploying upgraded, high-spec workover rigs. We have upgraded approximately forty-two high-spec workover rigs to date with fifteen of those delivered to customers in 2018, and we plan to deliver another eleven rigs to select customers in 2019. In our fluids management business, we plan to continue focusing on areas with improving fluids logistics and disposal demand, but potential growth opportunities will primarily be dependent upon asset availability and the easing of current labor constraints. Going forward, we will continue to focus on meeting improved customer demand and maintaining our strategy of aligning with customers who have deep inventories of work and who value our ability to safely deliver superior service quality, which should continue to result in increasing segment profitability and returns. That said, we are also exploring potential strategic opportunities for the Well Support Services business that would enable us to focus on growing our new well focused business.
Please see “Liquidity and Capital Resources” in this Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in addition to “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” in Part I, Item 1A of this Annual Report.
Regulations
The discussion set forth under Item 1. "Business - Government Regulations and Environmental, Health and Safety Matters" in our 2017 Annual Report is incorporated herein by reference.

45



On March 8, 2018, the President issued two Proclamations directing the imposition, effective March 23, 2018, of ad valorem tariffs of 25% on certain imported steel products and 10% on certain imported aluminum products from all countries, with the exception of Canada and Mexico. Subsequently, on March 22, 2018, the President issued two additional Proclamations that exempted, in addition to Canada and Mexico, several additional countries from the remedial tariff measures, as follows: (i) Argentina; (ii) Australia; (iii) Brazil; (iv) the 28 member countries of the European Union; and (v) South Korea. In Proclamations issued on April 30, 2018, the President: (i) permanently exempted South Korea from the imposition of tariffs on imported steel, while allowing tariffs to be imposed on imported aluminum; (ii) extended the steel and aluminum tariff exemptions for Argentina, Australia, and Brazil indefinitely to allow for continued negotiations; and (iii) extended the steel and aluminum tariff exemptions for Canada, Mexico, and the 28 member countries of the European Union to allow for continued negotiations, but only through May 31, 2018. In addition to possible country-based exemptions, the United States has established a protocol whereby individuals or entities using any of the affected steel or aluminum products in business activities, such as manufacturing, may request the exclusion of individual products from the imposition of tariffs. On May 31, 2018, the U.S. announced that it would also impose steel and aluminum tariffs on Canada, Mexico, and the 28 member countries of the European Union. In addition, Argentina, Australia, Brazil, and South Korea implemented measures to address the impairment to U.S. national security attributable to steel and aluminum imports that were deemed satisfactory to the United States. As a result, imports of steel and/or aluminum from these countries have been exempted from the imposition of tariff-based remedies, but, with the exception of Australia, the United States has implemented quantitative restrictions in the form of absolute quotas, meaning that imports in excess of the allotted quota will be disallowed.
Our R&T department is primarily engaged in the engineering and production of certain parts and components, such as perforating guns and addressable switches, which are used in the completion process. Certain of these items, particularly perforating guns used in our wireline operations, are manufactured using imported steel tubing, which is subject to a 25% tariff. We expect that, depending on the ultimate outcome of the country exemption and product exclusion processes described above, our raw material costs will increase and result in corresponding increases in the price of our finished goods. Further, in addition to the products manufactured by our R&T department, we expect that the costs of other high steel content products used in conjunction with our fracturing and coiled tubing operations, specifically power ends, fluid ends, treating iron and coiled tubing strings, will also increase as we expect the manufacturers of such goods to pass along the net effect the tariffs have on the cost of manufacturing such goods.
Liquidity and Capital Resources
Sources of Liquidity and Capital Resources
Our primary sources of liquidity have historically included, and we have funded our capital expenditures with, cash flows from operations, proceeds from public offerings of our common stock and borrowings under debt facilities. Our ability to generate future cash flows is subject to a number of variables, many of which are outside of our control, including the drilling, completion and production activity by our customers, which is highly dependent on oil and gas prices. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Industry Trends and Outlook” for additional discussion of certain factors that impact our results and the market challenges within our industry. See “-Financial Condition and Cash Flows” below for information about net cash provided by or used in our operating, investing and financing activities.
We have maintained a strong balance sheet and a conservative capital structure. As of December 31, 2018, we had a cash balance of $135.7 million and no borrowings drawn on our Credit Facility, which had $234.7 million of available borrowing capacity after taking into consideration outstanding letters of credit totaling $20.6 million. This resulted in total liquidity of $370.4 million as of December 31, 2018. As of February 22, 2019, we had a cash balance of approximately $84.9 million and no borrowings drawn on our Credit Facility, which had $234.7 million of available borrowing capacity after taking into consideration our current outstanding letters of credit totaling $20.6 million, resulting in total liquidity of approximately $319.6 million. Under the terms of our Credit Facility, the borrowing base is subject to monthly adjustments based on current levels of accounts receivable and inventory. For additional information about the Credit Facility, please see “Description of our Indebtedness” below and Note 3 - Debt in Part II, Item 8 “Financial Statements” of this Annual Report.
Our primary uses of cash are for operating costs, capital expenditures and other expenditures. The oilfield services business is capital-intensive, requiring significant investment to maintain, upgrade and purchase equipment to meet our customers’ needs and industry demand. Our capital expenditures consist primarily of:
growth capital expenditures, which are capital expenditures made to acquire additional equipment and other assets, increase our service lines, or advance other strategic initiatives for the purpose of growing our business; and

46



maintenance capital expenditures, which are capital expenditures related to our existing equipment, such as refurbishment and other activities to extend the useful life of partially or fully depreciated assets.
Capital expenditures totaled $311.1 million in 2018, primarily pertaining to the maintenance of deployed equipment, the refurbishment of previously stacked fracturing equipment and the building of new equipment for our Completion and Well Construction & Intervention Services segments. We decreased our 2018 capital expenditure budget in the second quarter from the initial estimated range of between $430.0 million and $450.0 million due to our decision to delay the refurbishment and future redeployment of three stacked horizontal frac fleets. We further decreased our capital expenditure budget in the third quarter due to less growth and maintenance capital spending in most of our core service lines as a result of lower activity levels and reduced customer demand.
On July 31, 2018, the Company's Board of Directors approved a stock repurchase program authorizing the repurchase, at the discretion of senior management, of up to $150.0 million of the Company’s common stock over the twelve month period starting August 1, 2018, in open market or in privately negotiated transactions, subject to U.S. Securities and Exchange Commission regulations, stock market conditions, capital needs of the business, and other factors. Repurchases may be commenced or suspended at any time without notice. In 2018, the Company executed the repurchase of approximately 2.4 million shares at an average cost of $16.55 per share.
We expect to fund our 2019 capital expenditure program primarily with cash flows from operations and potential borrowings under our Credit Facility. The amount of indebtedness we have outstanding at any time could limit our ability to finance future growth and could adversely affect our operations and financial condition. Based on our existing operating performance, we currently believe that our cash flows from operations, cash on hand and borrowings under our Credit Facility will be sufficient to meet our operational and capital expenditure requirements over the next twelve months.

Financial Condition and Cash Flows
The net cash provided by or used in our operating, investing and financing activities is summarized below:
 
 
Successor
 
 
Predecessor
 
 
(In thousands)
 
 
Years Ended December 31,
 
 
2018
 
2017
 
 
2016
Cash flow provided by (used in):
 
 
 
 
 
 
 
Operating activities
 
$
342,064

 
$
94

 
 
$
(107,372
)
Investing activities
 
(276,160
)
 
(275,686
)
 
 
(26,927
)
Financing activities
 
(44,426
)
 
210,339

 
 
174,264

Effect of exchange rate on cash
 
381

 
(2,102
)
 
 
(1,282
)
Increase (decrease) in cash and cash equivalents
 
$
21,859

 
$
(67,355
)
 
 
$
38,683

Cash Provided by (Used in) Operating Activities
Net cash provided by operating activities was $342.1 million for the year ended December 31, 2018. The cash inflow was primarily from (i) adjustments for non-cash items of $416.2 million, (ii) $51.3 million of positive changes in other operating assets and liabilities primarily from the decrease of previous period investment in working capital, and (iii) $4.6 million related to state income and federal income tax refunds. This cash inflow was offset by a net loss of $130.0 million.
Net cash provided by operating activities was $0.1 million for the year ended December 31, 2017. The cash inflow was primarily related to net income of $22.5 million, adjustments for non-cash items of $106.4 million, cash provided from the collection of accounts receivable assumed in the O-Tex acquisition and positive changes in other operating assets and liabilities, excluding accounts receivable, inventory, accounts payable and accrued expenses. This cash inflow was offset by $149.3 million of (i) increased investment in working capital (accounts receivable, inventory, accounts payable and accrued expenses) as a result of the increase in the demand primarily for our completion service lines and the resulting increase in revenue and direct costs for the year ended December 31, 2017 and (ii) cash used to satisfy obligations related to accounts payable and accrued liabilities assumed in the O-Tex acquisition.
Net cash used in operating activities was $107.4 million for the year ended December 31, 2016. The use of cash was primarily related to a net loss of $944.3 million, offset by (i) adjustments for non-cash items of $713.5 million, (ii) cash

47



inflows of $101.3 million due to a decrease in our investment in working capital (accounts receivable, inventory, accounts payable and accrued expenses) as a result of the decrease in the demand for our services and the resulting decrease in revenue and direct costs during the year ended December 31, 2016, (iii) a decrease in the use of cash related to accounts payable and accrued expenses during the third and fourth quarters of 2016 both resulting from the automatic stay associated with the Chapter 11 Proceeding and (iv) positive changes in other operating assets and liabilities, excluding accounts receivable, inventory, accounts payable and accrued expenses.
Cash Flows Used in Investing Activities
Net cash used in investing activities was $276.2 million for the year ended December 31, 2018. The use of cash was related to $311.1 million of capital expenditures primarily pertaining to the maintenance of deployed equipment, the refurbishment of previously stacked equipment and related reactivation costs for equipment redeployed in both the second and third quarters of 2018, and the building of new equipment for our Completion and WC&I segments. These amounts were offset by (i) $33.4 million of proceeds from the disposal of property, plant and equipment and non-core service lines and (ii) a $1.5 million refund from a purchase price adjustment related to the O-Tex acquisition.
Net cash used in investing activities was $275.7 million for the year ended December 31, 2017. The use of cash was related to (i) $210.2 million of capital expenditures primarily pertaining to the refurbishment of stacked equipment and the construction of new-build frac pumps and refurbished ancillary equipment and (ii) $133.8 million related to the O-Tex Transaction. These amounts were offset by $68.3 million of proceeds from the divestiture of non-core business lines previously reported under our Other Services reportable segment and from the disposal of property plant and equipment.
Net cash used in investing activities was $26.9 million for the year ended December 31, 2016. The use of cash was related to $57.9 million of capital expenditures primarily pertaining to the new ERP system and to costs incurred to extend the useful lives of our existing equipment, offset by $32.8 million of proceeds from the disposal of property plant and equipment.
Cash Flows Provided by Financing Activities
Net cash used by financing activities was $44.4 million for the year ended December 31, 2018. The cash used was related to (i) $37.1 million for share repurchases in connection with our stock repurchase program, (ii) $3.9 million of settlement and employee tax withholding on restricted stock vestings and (iii) $3.5 million of cash paid for financing costs related to our Credit Facility.
Net cash provided by financing activities was $210.3 million for the year ended December 31, 2017. The cash provided was primarily from $215.9 million of proceeds from the public offering of common stock, partially offset by (i) $3.8 million of employee tax withholding on restricted stock vesting and (ii) $1.7 million of cash paid for financing costs related to our Credit Facility.
Net cash provided by financing activities was $174.3 million for the year ended December 31, 2016. The cash provided was primarily from (i) $174.0 million in proceeds from the Predecessor's revolving credit facility and (ii) $23.0 million in proceeds from the DIP Facility. These amounts were offset by (i) $13.3 million in payments on the Predecessor's revolving credit facility and term debt, (ii) $5.6 million for excess tax expense from share-based compensation, (iii) $2.4 million in payments related to capital lease obligations and (iv) $1.0 million of cash paid for financing costs related to our DIP Facility.
Description of our Indebtedness
Credit Facility
We and certain of our subsidiaries (the “Borrowers”) entered into an Asset-Based Revolving Credit Agreement with, among others, JPMorgan Chase Bank, N.A., as administrative agent (the “Agent”), on May 1, 2018 (the "Credit Facility"). The maturity date of the Credit Facility is May 1, 2023. The Credit Facility replaces the Prior Credit Facility, which was canceled and discharged on May 1, 2018. For additional information about the Prior Credit Facility, please see Note 3 - Debt in Part II, Item 8 “Financial Statements” of this Annual Report.
The Credit Facility allows the Borrowers to incur revolving loans in an aggregate amount up to the lesser of (a) $400.0 million or (b) a borrowing base (the “Loan Cap”), which borrowing base is based upon the value of the Borrowers’ accounts receivable, inventory and restricted cash, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion. The Credit Facility also provides for the issuance of letters of credit, which would further

48



reduce borrowing capacity thereunder. If at any time the amount of loans and other extensions of credit outstanding under the Credit Facility exceed the borrowing base, the Borrowers may be required, among other things, to prepay outstanding loans immediately.
The Borrowers’ obligations under the Credit Facility are secured by liens on a substantial portion of the Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Borrowers’ real properties, may also be required to be pledged. Each of the Borrowers is jointly and severally liable for the obligations of the other Borrowers under the Credit Facility.
At the Borrowers’ election, interest on borrowings under the Credit Facility will be determined by reference to either LIBOR plus an applicable margin of between 1.50% and 2.00% or an “alternate base rate” plus an applicable margin of between 0.50% and 1.00%, in each case based on the Company’s total leverage ratio. Interest will be payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans and, in the case of an interest period longer than three months, quarterly, upon any prepayment and at final maturity. The Borrowers will also be required to pay a fee on the unused portion of the Credit Facility equal to (i) 0.50% per annum if average utilization is less than or equal to 25% or (ii) 0.375% per annum if average utilization is greater than 25%, in each case payable quarterly in arrears to the Agent.
The Credit Facility contains covenants that limit the Borrowers’ ability to incur additional indebtedness, grant liens, make loans, make acquisitions or investments, make distributions, merge into or consolidate with other persons, or engage in certain asset dispositions.
The Credit Facility also contains a financial covenant which requires us to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 upon the occurrence of an event of default or on any date upon which the excess availability is less than the greater of (x) 12.5% of the Loan Cap and (y) $30.0 million. The fixed charge coverage ratio is generally defined in the Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.
Contractual Obligations
The following table summarizes our contractual cash obligations as of December 31, 2018:
Contractual Obligations
 
Total
 
Less than
1 year
 
1-3 years
 
3-5 years
 
More than
5 years
 
 
(In thousands)

Service equipment and consumables
 
$
21,524

 
$
21,524

 
$

 
$

 
$

Operating leases
 
30,864

 
9,204

 
12,616

 
9,023

 
21

Credit Facility (1)
 
9,848

 
2,275

 
4,550

 
3,023

 

Administrative contracts
 
26,121

 
7,849

 
10,803

 
5,499

 
1,970

Total
 
$
88,357

 
$
40,852

 
$
27,969

 
$
17,545

 
$
1,991

(1) Represents unused commitment fees on unused portion of the Credit Facility and outstanding letters of credit. As of December 31, 2018, there were no amounts outstanding under the Credit Facility.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K, as of December 31, 2018.
Critical Accounting Policies
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting standards have developed. Accounting standards generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing standards, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable standards on or before their adoption, and we believe the proper implementation and consistent application of the accounting standards are critical.

49



Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, expenses and related disclosures. We base our estimates and assumptions on historical experience and on various other factors that we believe to be reasonable under the circumstances. We evaluate our estimates and assumptions on an ongoing basis. The results of our analysis form the basis for making assumptions about the carrying values of assets and liabilities that are not readily apparent from other sources. Our actual results may differ from these estimates under different assumptions or conditions.
We believe the following critical accounting policies involve significant areas of management’s judgments and estimates in the preparation of our consolidated financial statements.
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are generally stated at the amount billed to customers. We provide an allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Provisions for doubtful accounts are recorded when it is deemed probable that the customer will not make the required payments at either the contractual due dates or in the future.
Property, Plant and Equipment. Property, plant and equipment ("PP&E") are reported at cost less accumulated depreciation. Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to expense when incurred. Refurbishments are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operating income. The cost of property and equipment currently in service is depreciated, on a straight-line basis, over the estimated useful lives of the related assets.
PP&E are evaluated on a quarterly basis to identify events or changes in circumstances (“triggering events”) that indicate the carrying value of certain PP&E may not be recoverable. PP&E are reviewed for impairment upon the occurrence of a triggering event. An impairment loss is recorded in the period in which it is determined that the carrying amount of PP&E is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets with such cash flows to be realized over the estimated remaining useful life of the primary asset within the asset group, excluding interest expense. We determined the lowest level of identifiable cash flows that are independent of other asset groups to be primarily at the service line level. Our asset groups consist of well support services, fracturing services, cased-hole wireline and pumping services, cementing services and coiled tubing services. If the estimated undiscounted future net cash flows for a given asset group is less than the carrying amount of the related assets, an impairment loss is determined by comparing the estimated fair value with the carrying value of the related assets. The impairment loss is then allocated across the asset group's major classifications.
Goodwill, Indefinite-Lived Intangible Assets and Definite-Lived Intangible Assets. Goodwill may be allocated across three reporting units: Completion Services, Well Construction and Intervention Services ("WC&I") and Well Support Services. At the reporting unit level, we test goodwill for impairment on an annual basis as of October 31 of each year, or when events or changes in circumstances, referred to as triggering events, indicate the carrying value of goodwill may not be recoverable and that a potential impairment exists. Judgment is used in assessing whether goodwill should be tested for impairment more frequently than annually. Factors such as unexpected adverse economic conditions, competition, market changes and other external events may require more frequent assessments.
Before employing quantitative impairment testing methodologies, we may first evaluate the likelihood of impairment by considering qualitative factors relevant to each reporting unit, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. If we first utilize a qualitative approach and determine that it is more likely than not that goodwill is impaired, quantitative testing methodologies are then applied. Otherwise, we conclude that no impairment has occurred. Quantitative impairment testing involves comparing the fair value of each reporting unit to its carrying value, including goodwill. Fair value reflects the price a market participant would be willing to pay in a potential sale of the reporting unit. If the fair value exceeds carrying value, then it is concluded that no goodwill impairment has occurred. In connection with our adoption of ASU No. 2017-04, Simplifying the Test for Goodwill Impairment on January 1, 2018, if the carrying value of the reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to the excess, not to exceed the amount of goodwill allocated to the reporting unit.
Quantitative impairment testing involves the use of a blended income and market approach. Significant management judgment is necessary to evaluate the impact of operating and macroeconomic changes on each reporting unit.

50



Critical assumptions include projected revenue growth, fleet count, utilization, gross profit rates, sales, general and administrative ("SG&A") rates, working capital fluctuations, capital expenditures, discount rates, terminal growth rates, and price-to-earnings multiples. Our market capitalization is also used to corroborate reporting unit valuations.
Similar to goodwill, indefinite-lived intangible assets are subject to annual impairment tests or more frequently if events or circumstances indicate the carrying amount may not be recoverable.
Definite-lived intangible assets are amortized over their estimated useful lives and are reviewed for impairment when a triggering event occurs. With the exception of the C&J trade name, these intangibles, along with PP&E, are reviewed for impairment when a triggering event indicates that the asset group may have a net book value in excess of recoverable value. In these cases, we perform a recoverability test on our PP&E and definite-lived intangible assets by comparing the estimated future net undiscounted cash flows expected to be generated from the use of these assets to the carrying amount of the assets for recoverability. If the estimated undiscounted cash flows exceed the carrying amount of the assets, an impairment does not exist, and a loss will not be recognized. If the undiscounted cash flows are less than the carrying amount of the assets, the assets are not recoverable and the amount of impairment must be determined by fair valuing the assets. The C&J trade name is a corporate asset and is reviewed for impairment upon the occurrence of a triggering event by comparing the carrying amount of the corporate assets with the remaining cash flows available, after taking into consideration the lower level asset groups that benefit from the C&J trade name.
Mergers and Acquisitions. In accordance with accounting guidance for business combinations, we allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values. We typically engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as trade names and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, up to one year after the acquisition closing date as we obtain more information regarding asset valuations and liabilities assumed.
Our purchase price allocation methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques, including discounted cash flows and market multiple analysis. Unanticipated events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies. If actual results are materially different than the assumptions we used to determine fair value of the assets and liabilities acquired through a business combination, it is possible that adjustments to the carrying values of such assets and liabilities will have an impact on our net earnings.
See “Note 10 - Acquisitions” in Item 8 “Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the acquisition-related information associated with mergers and acquisitions completed in the last three fiscal years.
Revenue Recognition. We adopted Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers and its related updates as codified under ASC 606, Revenue from Contracts with Customers ("ASC 606") on January 1, 2018, using the modified retrospective method for all contracts not completed as of the date of adoption. The reported results for the year ended December 31, 2018 reflect the application of ASC 606 guidance while the reported results for the corresponding prior year period were prepared under the previous guidance of ASC No. 605, Revenue Recognition ("ASC 605"). After reviewing our contracts and the revenue recognition guidance under ASC 606, there are no material differences between revenue recognition under ASC 605 and ASC 606. As a result, there is not a cumulative effect adjustment recorded to beginning retained earnings or recognition of any contract assets or liabilities upon adoption of ASC 606.
The adoption of ASC 606 represents a change in accounting principle that more closely aligns revenue recognition with the performance of our services and provides financial statement readers with enhanced disclosures. In accordance with ASC 606, revenue is recognized in a manner reflecting the transfer of goods or services to customers based on consideration a company expects to receive. We recognize revenue when we satisfy a performance obligation by transferring control over a product or service to a customer. To achieve this core principle, ASC 606 requires we apply the following five steps: (1) identify the contract with a customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to performance obligations in the contract, and (5) recognize revenue when or as we satisfy a performance obligation. The five-step model requires management to exercise judgment when evaluating contracts and recognizing revenue.

51



Share-Based Compensation. Our share-based compensation plan provides the ability to grant equity awards to our employees, consultants and non-employee directors. As of December 31, 2018, only nonqualified stock options, restricted shares, performance stock and restricted share units had been granted under such plans. The fair value of restricted share grants and restricted share units is based on the closing price of our common stock on the grant date. We values option grants based on the grant date fair value using the Black-Scholes option-pricing model, and we value performance awards with market conditions based on the grant date fair value using a Monte Carlo simulation, both of which require the use of subjective assumptions. We recognize share-based compensation expense on a straight-line basis over the requisite service period for the entire award and makes estimates of employee terminations and forfeiture rates which impacts the amount of compensation expense that is recorded over the requisite service period.
Income Taxes. We are subject to income and other similar taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of our annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when we recognize income tax expenses and benefits.
We account for income taxes utilizing the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized as income or expense in the period that includes the enactment date.
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. In assessing the likelihood and extent that deferred tax assets will be realized, consideration is given to projected future taxable income and tax planning strategies. A valuation allowance is recorded when, in the opinion of management, it is more likely than not that a portion or all of the deferred tax assets will not be realized.
We have federal, state and international net operating losses ("NOLs") carried forward from tax years ending before January 1, 2018 that will expire in the years 2020 through 2038. Due to U.S. tax reform, any U.S. federal income tax losses incurred for tax years beginning after December 31, 2017 can be carried forward indefinitely with no carry back available.  In addition, the taxable losses generated in tax years beginning after December 31, 2017 can only offset 80% of taxable income generated in tax years beginning after December 31, 2018. After considering the scheduled reversal of deferred tax liabilities, projected future taxable income, the potential limitation on use of NOLs under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code") and tax planning strategies, we established a valuation allowance due to the uncertainty regarding the ultimate realization of the deferred tax assets associated with its NOL carryforwards.
As a result of the Chapter 11 Proceeding, on the Plan Effective Date, we believe we experienced an ownership change for purposes of Section 382 of the Code because of its Restructuring Plan. Consequently, our pre-change NOLs are subject to an annual limitation (See Note 14 - Chapter 11 Proceeding and Emergence for additional information, including definitions of capitalized defined terms, about the Chapter 11 Proceeding and emergence from the Chapter 11 Proceeding). The ownership change and resulting annual limitation on use of NOLs are not expected to result in the expiration of our NOL carryforwards if we are able to generate sufficient future taxable income within the carryforward periods. However, the limitation on the amount of NOLs available to offset taxable income in a specific year may result in the payment of income taxes before all NOLs have been utilized. Additionally, a subsequent ownership change may result in further limitation on the ability to utilize existing NOLs and other tax attributes, which could cause our pre-change NOL carryforwards to expire unused.
We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50.0% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized uncertain tax positions are reversed in the first period in which it is more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. For the year ended December 31, 2018, we have an unrecognized tax benefit of $6.0 million related to an increase in the estimate of the reserve for unrecognized tax benefits relating to our uncertain tax positions, which is netted against our net operating loss carryforwards. The unrecognized tax benefit, or UTB, is related to a deduction for certain fees that were paid using shares of our common stock as part of the January 7, 2017 plan of reorganization. The recorded unrecognized tax benefit is equal to our estimate of the portion of the tax benefit that is less than 50% likely to be realized upon ultimate settlement with a taxing

52



authority.
Recent Accounting Pronouncements
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). ASU No. 2016-02 seeks to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and by disclosing key information about leasing arrangements. Unlike current U.S. GAAP, which requires only capital leases to be recognized on the balance sheet, ASU No. 2016-02 will require both operating and finance leases to be recognized on the balance sheet. Additionally, the new guidance will require disclosures to help investors and other financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements.
The amendments in ASU No. 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We adopted this new accounting standard on January 1, 2019 using the modified retrospective approach. Under this transition method, leases existing at, or entered into after the adoption date are required to be recognized and measured. We have elected to use the effective date as its date of initial application, consequently prior period amounts have not been adjusted and continue to be reflected in accordance with historical accounting. We elected the package of practical expedients which permits us to not reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. We have also elected the practical expedient to combine the lease and non-lease components of a contract for all of our contracts, as well as the short-term lease recognition exemption.
The adoption of this standard will result in the initial recognition of approximately $25.0 million to $28.0 million of right-of-use assets and operating lease liabilities, with no related impact to consolidated stockholders' equity or net income (loss).
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which amends U.S. GAAP by introducing a new impairment model for financial instruments that is based on expected credit losses rather than incurred credit losses. The new impairment model applies to most financial assets, including trade accounts receivable. The amendments in ASU 2016-13 are effective for interim and annual reporting periods beginning after December 15, 2019, although it may be adopted one year earlier, and requires a modified retrospective transition approach. We are currently evaluating the impact this standard will have on our results of operations and financial position.
In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory ("ASU 2016-16"), which requires an entity to recognize the income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, when the transfer occurs. The ASU is effective for the interim and annual reporting periods beginning after December 15, 2017, including interim periods within those fiscal years, and early application is permitted. We adopted this new accounting standard on January 1, 2018, and upon adoption recognized a cumulative effect adjustment as a reduction to retained earnings of $13.2 million.
In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"), which establishes a one-step process for testing goodwill for impairment. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019 and early adoption is permitted. We early adopted this new accounting standard on January 1, 2018 and there no impact on our consolidated financial statements upon adoption. As part of our annual impairment assessment of goodwill during the fourth quarter of 2018, we applied this new accounting standard and recognized an impairment charge of $146.0 million for the year ended December 31, 2018.
In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ("ASU 2018-02"), which allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act and requires certain disclosures about stranded tax effects. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.
In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118, ("ASU 2018-05"), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (the Tax Act) pursuant to Staff Accounting Bulletin No. 18, which allows companies to

53



complete the accounting under ASC 740 within a one-year measurement period from the Tax Act enactment date. This standard is effective upon issuance. We adopted this new accounting standard January 1, 2018, and there was no impact on our consolidated financial statements upon adoption.
In June 2018, the FASB issued ASU No. 2018-07, Compensation-Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting, ("ASU 2018-07"), which expands the scope of Topic 718 to include all share-based payment transactions for acquiring goods and services from nonemployees. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2018, and early adoption is permitted. We adopted this new accounting standard January 1, 2019, and there was no impact on our consolidated financial statements upon adoption.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement ("ASU 2018-13"), which modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other Internal-Use Software (Subtopic 350-50): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract ("ASU 2018-15"), which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2018, 2017 and 2016. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy, and we tend to experience inflationary pressure on the cost of our equipment, materials and supplies as increasing oil and natural gas prices increase activity in our areas of operations.

54



Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is commodity price risk, which is the risk related to increases in the prices of fuel, materials and supplies consumed in performing our services. We are also exposed to risks related to interest rate fluctuations and customer credit.
Commodity Price Risk. Our material and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation services such as proppants, chemicals, guar, coiled tubing and fluid supplies. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials (particularly guar and proppants) in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Historically, we have generally been able to pass along price increases to our customers; however, we may be unable to do so in the future. We do not engage in commodity price hedging activities.
Interest Rate Risk. We are exposed to changes in interest rates on our floating rate borrowings under our Credit Facility. As of December 31, 2018, we had no debt outstanding under our Credit Facility. The impact of a 1.0% increase in interest rates under the terms of the Credit Facility would have no impact on interest expense for the 2018 year.
Customer Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk are trade receivables. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including credit evaluations and maintaining an allowance for doubtful accounts.

55


Item 8. Financial Statements and Supplementary Data
Index to
Consolidated Financial Statements
 
 
 
Management's Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firms
Consolidated Balance Sheets as of December 31, 2018 and 2017
Consolidated Statements of Operations for the Years Ended December 31, 2018 and 2017 (Successor), on January 1, 2017 (Predecessor) and for the Year Ended December 31, 2016 (Predecessor)
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2018 and 2017 (Successor), on January 1, 2017 (Predecessor) and for the Year Ended December 31, 2016 (Predecessor)
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2018 and 2017 (Successor), on January 1, 2017 (Successor) and for the Year Ended December 31, 2016 (Predecessor)
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018 and 2017 (Successor), on January 1, 2017 (Predecessor) and for the Year Ended December 31, 2016 (Predecessor)
Notes to Consolidated Financial Statements


56


Management’s Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act). Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States and includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management with the participation of the Company’s principal executive and financial officers assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018. In making this assessment, it used the criteria set forth in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Management’s assessment included an evaluation of the design of internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Based on this assessment, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2018.
The Company's internal control over financial reporting as of December 31, 2018 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears in this Form 10-K.
 
 
 
 
 
/s/ Donald J. Gawick
 
 
/s/ Jan Kees van Gaalen
 
 
/s/ Michael S. Galvan

Donald J. Gawick
President, Chief Executive Officer and Director (Principal Executive Officer)
 
Jan Kees van Gaalen
Chief Financial Officer (Principal Financial Officer)
 
Michael S. Galvan
Chief Accounting Officer and Treasurer
(Principal Accounting Officer)
February 27, 2019


57



Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
C&J Energy Services, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of C&J Energy Services, Inc. (the Company) as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for the years ended December 31, 2018 and 2017 (Successor), and for the year ended 2016 (Predecessor), and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for the years ended December 31, 2018 and 2017 (Successor) and for the year ended 2016 (Predecessor), in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company's auditor since 2014.
Houston, Texas
February 27, 2019


58


Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
C&J Energy Services, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited C&J Energy Services, Inc.’s (the Company) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 and 2017, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for the years ended December 31, 2018 and 2017 (Successor), and for the year ended December 31, 2016 (Predecessor), and related notes (collectively, the consolidated financial statements), and our report dated February 27, 2019 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Houston, Texas
February 27, 2019
 

59



C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
 
 
 
December 31, 2018
 
December 31, 2017
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
135,746

 
$
113,887

Accounts receivable, net of allowance of $4,877 at December 31, 2018 and $4,269 at December 31, 2017
 
309,104

 
367,906

Inventories, net
 
62,633

 
77,793

Prepaid and other current assets
 
22,357

 
33,011

Total current assets
 
529,840

 
592,597

Property, plant and equipment, net of accumulated depreciation of $320,134 at December 31, 2018 and $133,755 at December 31, 2017
 
737,292

 
703,029

Other assets:
 
 
 
 
Goodwill
 

 
147,515

Intangible assets, net
 
115,072

 
123,837

Deferred financing costs, net of accumulated amortization of $2,932 at December 31, 2018 and $608 at December 31, 2017
 
4,574

 
3,379

Other noncurrent assets
 
37,676

 
38,500

Total assets
 
$
1,424,454

 
$
1,608,857

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
140,109

 
$
138,624

Payroll and related costs
 
48,873

 
52,812

Accrued expenses
 
55,430

 
67,414

Total current liabilities
 
244,412

 
258,850

Deferred tax liabilities
 
537

 
3,917

Other long-term liabilities
 
26,176

 
24,668

Total liabilities
 
271,125

 
287,435

Commitments and contingencies
 
 
 
 
Stockholders’ equity
 
 
 
 
Common stock, par value of $0.01, 1,000,000,000 shares authorized, 66,120,015 and 68,546,820 issued and outstanding at December 31, 2018 and December 31, 2017, respectively
 
661

 
686

Additional paid-in capital
 
1,273,524

 
1,298,859

Accumulated other comprehensive loss
 
(148
)
 
(580
)
Retained earnings (deficit)
 
(120,708
)
 
22,457

Total stockholders’ equity
 
1,153,329

 
1,321,422

Total liabilities and stockholders’ equity
 
$
1,424,454

 
$
1,608,857


See accompanying notes to consolidated financial statements

60



C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
 
 
 
Successor
 
 
Predecessor
 
 
Years Ended December 31,
 
 
On January 1,
 
Year Ended December 31,
 
 
2018
 
2017
 
 
2017
 
2016
Revenue
 
$
2,222,089

 
$
1,638,739

 
 
$

 
$
971,142

Costs and expenses:
 
 
 
 
 
 
 
 
 
Direct costs
 
1,724,707

 
1,288,092

 
 

 
947,255

Selling, general and administrative expenses
 
225,511

 
250,871

 
 

 
229,267

Research and development
 
6,286

 
6,368

 
 

 
7,718

Depreciation and amortization
 
224,867

 
140,650

 
 

 
217,440

Impairment expense
 
146,015

 

 
 

 
436,395

(Gain) loss on disposal of assets
 
25,676

 
(31,463
)
 
 

 
3,075

Operating loss
 
(130,973
)
 
(15,779
)
 
 

 
(870,008
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(3,899
)
 
(1,527
)
 
 

 
(157,465
)
Other income (expense), net
 
2,453

 
3

 
 

 
9,504

Total other expense
 
(1,446
)
 
(1,524
)
 
 

 
(147,961
)
Loss before reorganization items and income taxes
 
(132,419
)
 
(17,303
)
 
 

 
(1,017,969
)
Reorganization items
 

 

 
 
(293,969
)
 
55,330

Income tax benefit
 
(2,414
)
 
(39,760
)
 
 
(4,613
)
 
(129,010
)
Net income (loss)
 
$
(130,005
)
 
$
22,457

 
 
$
298,582

 
$
(944,289
)
Net income (loss) per common share:
 
 
 
 
 
 
 
 
 
Basic
 
$
(1.94
)
 
$
0.37

 
 
$
2.52

 
$
(7.98
)
Diluted
 
$
(1.94
)
 
$
0.37

 
 
$
2.52

 
$
(7.98
)
Weighted average common shares outstanding:
 
 
 
 
 
 
 
 
 
Basic
 
66,897

 
61,208

 
 
118,633

 
118,305

Diluted
 
66,897

 
61,460

 
 
118,633

 
118,305

See accompanying notes to consolidated financial statements

61



C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
 
Successor
 
 
Predecessor
 
Years Ended December 31,
 
 
On January 1,
 
Year Ended December 31,
 
2018
 
2017
 
 
2017
 
2016
Net income (loss)
$
(130,005
)
 
$
22,457

 
 
$
298,582

 
$
(944,289
)
 
 
 
 
 
 
 
 
 
Other comprehensive income (loss):
 
 
 
 
 
 
 
 
Foreign currency translation gain (loss), net of income tax (expense) benefit of $23, ($777) and ($31) at December 31, 2018, 2017 and 2016, respectively
432

 
(580
)
 
 

 
1,425

Comprehensive income (loss)
$
(129,573
)
 
$
21,877

 
 
$
298,582

 
$
(942,864
)

See accompanying notes to consolidated financial statements