C&J Energy Services, Inc. - FORM 10-K

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 - C&J Energy Services, Inc.	cjes12312017ex-321.htm
EX-32.2 - EXHIBIT 32.2 - C&J Energy Services, Inc.	cjes12312017ex-322.htm
EX-31.2 - EXHIBIT 31.2 - C&J Energy Services, Inc.	cjes12312017ex-312.htm
EX-31.1 - EXHIBIT 31.1 - C&J Energy Services, Inc.	cjes12312017ex-311.htm
EX-23.1 - EXHIBIT 23.1 - C&J Energy Services, Inc.	cjes12312017ex-231.htm
EX-21.1 - EXHIBIT 21.1 - C&J Energy Services, Inc.	exhibit211listofsignifican.htm

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, 2017



¨	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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein and will not be contained, to the best of 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 or a smaller reporting 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	¨ (do not check if a smaller reporting company)	Smaller reporting company	¨

Emerging growth company	¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No ý

The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2017 (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 $1.9 billion.

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at February 27, 2018, was 68,465,637.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for its 2018 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2017, are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS



		Page
PART I

Item 1.	Business	3

Item 1A.	Risk Factors	18

Item 1B.	Unresolved Staff Comments	31

Item 2.	Properties	31

Item 3.	Legal Proceedings	32

Item 4.	Mine Safety Disclosures	33

PART II

Item 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	34

Item 6.	Selected Financial Data	36

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	37

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	64

Item 8.	Financial Statements and Supplementary Data	65

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	118

Item 9A.	Controls and Procedures	118

Item 9B.	Other Information	120

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	121

Item 11.	Executive Compensation	121

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	121

Item 13.	Certain Relationships and Related Transactions, and Director Independence	121

Item 14.	Principal Accounting Fees and Services	121

PART IV

Part 15.	Exhibits, Financial Statement Schedules	122

	Signatures	125

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, the impact of our emergence from bankruptcy on our business and relationships, future sales of or the availability for future sale of substantial amounts of our common stock, including the exercise of outstanding Warrants, our strategic plan, our business strategy and our financial strategy, including our ability to maintain sufficient liquidity.

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 declining commodity prices, overcapacity 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 E&P companies;


•	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 core 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 on our core 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, regulatory compliance requirements and other difficulties in executing our long-term growth strategy;


•	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;


•	business growth outpacing the capabilities of our infrastructure;


•	adverse weather conditions in oil or gas producing regions;


•	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;


•	the incurrence of significant costs and liabilities or severe restrictions on our operations or the inability to perform certain operations resulting from a failure to comply, or our compliance with, new or existing regulations;


•	the loss of, or inability to attract, key management and other competent personnel;


•	a shortage of qualified workers;


•	the loss of, or interruption or delay in operations by, one or more of our key suppliers;


•	operating hazards inherent in our industry, including the possibility of accidents resulting in personal injury or death, property damage or environmental damage;


•	accidental 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 amended credit facility.

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.

Item 1.

Introduction and Corporate 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 (as defined below), “C&J” the “Company,” “we,” “us” or “our”) is a leading provider of well construction, well completion, well support and other complementary oilfield services to oil and gas exploration and production (“E&P”) companies throughout the continental United States. We offer a comprehensive integrated suite of services throughout the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, directional drilling, rig services, fluids management, artificial lift and other completion and specialty well site 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.” 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 nearly tripled the Company’s size, significantly expanding the Company’s Completion Services business and adding 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” or the “Company”), and shares of common stock of Old C&J were converted into common shares of the Predecessor on a 1-for-1 basis.

Due to a severe industry downturn, on July 20, 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 (the “Bankruptcy Court”), with ancillary recognition proceedings filed in Canada and Bermuda (collectively, the “Chapter 11 Proceeding”).

On December 16, 2016, the Bankruptcy Court entered an order confirming the plan of reorganization (the “Restructuring Plan”) of the Predecessor Companies. On January 6, 2017 (the “Plan Effective Date”), the Predecessor Companies substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. As part of the transactions undertaken pursuant to the Restructuring Plan, effective on the Plan Effective Date, the Successor was formed, the Predecessor’s equity was canceled, the Predecessor transferred all of its assets and operations to the Successor and the Predecessor was subsequently dissolved. For more information regarding the Chapter 11 Proceeding, see Note 2 - Chapter 11 Proceeding and Emergence in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K (this “Annual Report”).

Upon emergence from the Chapter 11 Proceeding, we adopted Fresh Start accounting in accordance with the provisions set forth in Accounting Standards Codification (“ASC”) 852 - Reorganizations. For more information regarding the adoption of Fresh Start accounting, see Note 3 - Fresh Start Accounting in Part II, Item 8 “Financial Statements and Supplementary Data” of 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.

Contemporaneously with the commencement of the Chapter 11 Proceeding, trading in the Predecessor’s common stock was suspended and 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.”

We file annual, quarterly and current reports and other documents with the U.S. Securities and Exchange Commission (“SEC”) under the Exchange Act. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operations of the Public Reference Room by calling the SEC at (800) SEC-0330. In addition, the SEC maintains a website at www.sec.gov that contains reports and other information regarding issuers that file electronically with the SEC.

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 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.

Business Overview

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. Beginning in 2011 through mid-2015, we significantly invested in a number of strategic initiatives to strengthen, expand and diversify our business, including through service line diversification, vertical integration and technological advancement (“R&T”). During that time, we rapidly grew our business both organically and through multiple acquisitions, including the Nabors Merger.

During 2016 and into the first quarter of 2017, we divested several of our small, non-core businesses, including our specialty chemical business, equipment manufacturing and repair business, and our international coiled tubing operations in the Middle East. These divestitures, as well as the sale of our Canadian Well Support Services business in November 2017 discussed below, reflect a refocusing of our growth strategy in line with our goal of being the leading U.S. provider in all of our core services. Additionally, in furtherance of our strategy, we have continued to rightsize our U.S. Well Support Services segment, while we accelerated the growth of our cementing services with the O-Tex Transaction, described below.

We emerged from the Chapter 11 Proceeding as the market was beginning to recover. During 2017, we focused on the continuous improvement of our organization, including several ongoing initiatives purposed to optimize our business processes and gain greater efficiency over time. We also took a deliberate approach to increasing our core capabilities, adding capacity, and growing our core service lines.

The O-Tex Transaction

On October 25, 2017, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) by and among Caymus Merger Sub, Inc., a Delaware corporation and wholly owned direct subsidiary of the Company (“Merger Sub”), O-Tex Holdings, Inc., a Texas corporation (“O-Tex”), the stockholders of O-Tex (the “Stockholders”), and O-Tex Sellers Representative LLC, a Delaware limited liability company, in its capacity as representative of the Stockholders (the “Stockholders’ Representative”), providing for the merger of Merger Sub with and into O-Tex (the “Merger”), with O-Tex surviving the Merger, and immediately thereafter, the merger of O-Tex with and into another wholly owned direct subsidiary of the Company (together with the Merger and the other transactions contemplated by the Merger Agreement, the “O-Tex Transaction”).

On November 30, 2017 (the “Closing Date”), each holder of (i) outstanding common stock, par value $0.01 per share, of O-Tex (the “O-Tex Common Stock”), (ii) Series A Preferred Stock, par value $0.01 per share, of O-Tex (the “Series A Preferred Stock”) and (iii) Series B Preferred Stock, par value $0.01 per share, of O-Tex (together with the Series A Preferred Stock and the O-Tex Common Stock, the “O-Tex Shares”) had its O-Tex Shares (excluding any O-Tex Shares held in the treasury of O-Tex or held by the Company or Merger Sub immediately prior to the effective time of the Merger) converted into the right to receive such Stockholders’ pro rata portion of 4,420,000 shares of common stock, par value $0.01 per share, of the Company (the “Specified C&J Common Stock”). In addition, we paid to the Stockholders’ Representative, and each Stockholder became entitled to receive a pro rata portion of, $90.8 million in cash. The cash portion of the merger consideration was determined based on $132.5 million of base cash merger consideration, which was subject to closing adjustments as provided in the Merger Agreement (including reductions for the repayment of O-Tex’s indebtedness and transaction expenses) and may be further adjusted post-closing as provided in the Merger Agreement (including reductions for the payment of certain amounts into escrow for post-closing working capital adjustments and the satisfaction of post-closing indemnification obligations).

The foregoing description of the Merger Agreement does not purport to be complete and is qualified in its entirety by reference to the Merger Agreement, which was filed as Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on October 26, 2017, and is incorporated herein by reference.

Canadian Well Support Service Divestiture

On October 30, 2017, we entered into an Asset Purchase Agreement (the “Purchase Agreement”) with CWC Energy Services Corp., an Alberta corporation (“CWC”), and C&J Energy Production Services-Canada Ltd., an Alberta corporation and an indirect wholly owned subsidiary of the Company (“C&J Canada”), whereby CWC, among other things, acquired the assets of C&J Canada included in the Purchased Business (as defined in the Purchase Agreement) for total consideration of CDN $37.5 million in cash (the “Canadian Divestiture”).

With the closing of the Canadian Divestiture on November 5, 2017, we have completely exited the Well Support Services business in Western Canada, and we are no longer providing any oilfield services in Canada.

Our Reportable Business Segments and Strategy

As of December 31, 2017, our reportable business segments were:


•	Completion Services, which consists of the following businesses and service lines: (1) fracturing; (2) cased-hole wireline and pumping services; (3) well construction & intervention services, which includes cementing, coiled tubing and directional drilling services; and (4) completion support services, which includes our R&T department and data control instruments business.


•	Well Support Services, which consists of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) special services, which includes plug and abandonment, artificial lift applications and other specialty well site services.

Our Other Services segment consisted of smaller, non-core business lines that have since been divested, including our specialty chemical business, equipment manufacturing and repair business and our international coiled tubing operations in the Middle East. In line with the discontinuance of these small, ancillary service lines and divisions, subsequent to the year ended December 31, 2016, we are now disclosing two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period.

Each reportable business segment is described in more detail below; for additional financial information about each of our reportable business segments, including revenue from external customers and total assets by reportable business segment, see Note 13 - Segment Information in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report. Our results of operations in our core service lines are driven primarily by four 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, 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 products 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 service performance.

Management evaluates the performance of our reportable segments primarily based on Adjusted EBITDA because management believes Adjusted EBITDA provides important information about the activity and profitability of our lines of business within each reportable business segment and aids us in analytical comparisons for purposes of, among other things, efficiently allocating our assets and resources. Our management team also monitors asset utilization, among other factors, for purposes of assessing our overall activity levels and customer demand. For our Completion Services operations, 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 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. In our Well Support Services operations, we measure activity levels primarily by the number of hours our assets work on a monthly basis, based on the available working days per month. However, given the variance 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, undue reliance should not be placed on asset utilization as an indicator of our financial or operating performance. For additional information about Adjusted EBITDA for each of our reportable business segments, please see Note 13 - Segment Information in Part II, Item 8 "Financial Statements and Supplementary Data" of this Annual Report.

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 our alignment with customers who recognize the value that we provide through efficiency gains 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

Fracturing. With a fleet of approximately 900,000 hydraulic horsepower (“HHP”) we are 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.

Casedhole 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 with a fleet of 124 wireline trucks and 68 pumpdown units. 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 charges, providing us with a competitive advantage and enabling higher returns.

Cementing. Following the closing of the O-Tex Transaction, we are one of the largest providers of specialty cementing services in the United States, with 117 units. Our operations are supported by eight full-service laboratory facilities with advanced capabilities.

Coiled Tubing. With a fleet of 44 coiled tubing units, 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. Approximately 70 percent 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.

During 2017, we steadily refurbished and redeployed previously stacked equipment, and due to the continued strong near-term outlook, we are currently planning to deploy additional refurbished equipment over the course of 2018. Additionally, at any given time, our deployed assets may not be utilized fully or at all, due to, among other things, routine scheduled maintenance and downtime.

For the year ended December 31, 2017, revenue from our Completion Services segment was $1.3 billion, representing approximately 76.7% of our total revenue, with net income of $161.1 million and Adjusted EBITDA of $221.9 million.

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 special services, including plug and abandonment, artificial lift applications and other specialty well site services. 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 business segment.

Rig Services. As part of our services that help prolong the productive life of an oil or gas well, we operate the third largest fleet in the United States, consisting of 384 workover and well servicing rigs. These rigs range from 150 to 900 horsepower and 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 utilizing a service fleet of 1,090 fluid trucks and trailers and 3,503 portable tanks. This large 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 73 specialized trucks and trailers that are optimized to transport condensate. We also own 25 private salt water disposal wells. Demand and pricing for our fluids management services generally correspond to demand for our rig services.

We also provide certain other special services, including artificial lift applications and other specialty well site services.

For the year ended December 31, 2017, revenue from our Well Support Services segment was $382.2 million, representing approximately 23.3% of our total revenue, with net loss of $19.4 million and Adjusted EBITDA of $9.2 million.

Other Services

Our Other Services segment consisted of smaller, non-core business lines that have since been divested, including our specialty chemical business, equipment manufacturing and repair business and the Company's international coiled tubing operations in the Middle East. In line with the discontinuance of these small, ancillary service lines and divisions, subsequent to the year ended December 31, 2016, we are now disclosing two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period.

Other Information About Our Business

Geographic Areas

We operate in all active onshore basins in the continental United States. During the year ended December 31, 2017, approximately $1.6 billion, or 97.5%, of our consolidated revenue from external customers was derived from the United States, and the majority of our long lived assets were located in the United States. We also generated approximately $4.3 million, or 0.3% of our 2017 consolidated revenue from our Completions Service operations in Canada and $35.9 million, or 2.2%, of our 2017 consolidated revenue from our Well Support Service operations in Canada and approximately $0.9 million, or less than 0.1%, of our 2017 consolidated revenue from our artificial lift applications business in Ecuador and the Middle East. With the closing of the Canadian Divestiture on November 5, 2017, we have completely exited the Well Support Services business in Western Canada, and we are no longer providing any oilfield services in Canada.

From late 2011 through mid-2016, we worked to establish an operational presence in key countries in the Middle East, and opened offices in Dubai, Saudi Arabia and Oman. We were successful in winning a short-term contract to provide coiled tubing services in Saudi Arabia, which we completed in September 2015. However, we were not successful in winning any other work in Saudi Arabia or elsewhere in the region. Given our financial position and the severe industry downturn, coupled with changes in our executive management team with a resulting shift in short- and long-term growth strategy, in mid-2016 we re-evaluated our business plan with respect to international expansion generally, and the Middle East specifically. We determined that it was appropriate to significantly scale back our investment in this area to preserve liquidity and focus on the advancement of our core business in the United States. We are in the process of unwinding our footprint in the region, including selling assets and excess inventory to other operators in the region. The only business line we are currently offering in the Middle East is our artificial lift systems.

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 Completion Services and Well Support Services are primarily generated by the efforts of our sales force, working closely with our operations teams. In our core business lines of fracturing and rig services, these services are typically contracted well in advance for relatively long durations, which can result in sales backlogs during periods of high demand for our services. Our other core services are typically contracted on an ad hoc basis and as such generally have no, or very limited, sales backlogs. Our ability to deliver integrated services through the life of the well and strong track record provides cross-selling opportunities with existing customers.

Sales and marketing activities are typically performed through our local operations in each geographic region, with the exception of fracturing, which is centralized to a specific sales team at the corporate level. 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 streamlines our customer onboarding process. Our sales representatives work closely with our local managers and field sales personnel to target compelling market opportunities. 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 will also allow us to further expand our customer base.

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, scale, diversification, expertise and efficiency capabilities. We monitor closely 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 40.7%, 46.0% and 53.6% of our consolidated revenue for the years ended December 31, 2017, 2016 and 2015, respectively. There were no individual customers that accounted for more than 10.0% of our consolidated revenues during the year ended December 31, 2017 and December 31, 2016. For the year ended December 31, 2015, revenue from Oxy USA, Inc. individually represented 15.5% of our consolidated revenue. Other than the customer listed above, no other customer accounted for more than 10.0% of our consolidated revenue in 2015. If we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.

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 in the past been negatively affected by increases in supply relative to demand in our core 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 over the course of 2015 and 2016, and the consequent negative impact on the level of drilling, completion and production activity and capital expenditures by our customers, adversely affected the demand for our services. This, in turn, negatively impacted our ability to maintain adequate utilization of our asset base and to negotiate pricing at levels generating sufficient margins. The impact to our financial and operational performance ultimately led to the Chapter 11 Proceeding.

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’ greater resources could allow them to compete more effectively than we can, including by reducing prices for services in our core operating areas. Our major competitors for our Completion Services include Halliburton, Schlumberger, BJ Services, Keane Group, RPC, Inc., FTS International, Inc. (formerly known as Frac Tech Services), Basic Energy Services, Superior Energy Services, CalFrac Well Services, a significant number of regional, mostly-private businesses. Our major competitors for our Well Support Services include Key Energy Services, Basic Energy Services, Superior Energy Services, Ranger Energy Services, Precision, Forbes and Pioneer Energy Services, as well as a significant number of mostly-private, regional businesses.

Generally, we believe that the principal competitive factors in the markets that we serve are price, technical expertise, equipment capacity, 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 commodity prices such as those we experienced from late 2014 through 2016. Throughout the industry downturn, as a whole, our customer base generally prioritized receiving the lowest service cost pricing possible. 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 the downturn, our utilization and pricing levels were also negatively impacted by predatory pricing from certain large competitors, who elected to operate at negative margins for these services.

During healthier market conditions, we believe many of our customers choose to work with us based on our diversified service offering and 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 - 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, power ends and pump consumables) used in our Completion 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 these materials or products and we believe that we would be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers. 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, 2017, two suppliers from our Completions Services segment, Gardner Denver, Inc. and Unimin Corporation, supplied 9.7% and 7.2%, respectively, of our total Company's materials and/or products; but no single third party supplier from our Well Services segment supplied 5.0% or more of the Company's materials and/or products. Additionally, with respect to our Completion Services segment, as part of the Chapter 11 Proceeding we rejected all of our take or pay contracts for proppant and chemicals, which enabled us to negotiate two new proppant contracts covering approximately 80.0% of our forecasted volume needs for 2018 and beyond. 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 stacked hydraulic fracturing equipment.

Quality, Health, Safety and Environmental (“QHSE”) Program

Our business involves the operation of heavy and powerful equipment and the use of explosive and radioactive materials which can result in serious injuries to our employees and 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 efficiency of our operations. We believe that our QHSE policies and procedures, which are reviewed internally for compliance with industry changes, provide a solid 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 developing a best-in-class 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 certification 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, the use of explosives and radioactive materials, oil spills, surface and underground pollution and contamination, hazardous material spills, loss of well control, loss of or damage to the wellbore, formation or underground reservoir, damaged or lost equipment, 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, environmental and natural resources damage and damage to the property of others. Additionally, because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which 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.

Despite our efforts to maintain high safety standards, we from time to time have suffered accidents, and it is likely that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, and 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.

We maintain insurance policies for workers’ compensation, 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. We have deductibles per occurrence for: workers’ compensation 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.

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.

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 liability not indemnified by our customers in excess of our insurance coverage. 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 seek 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 losses, 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 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 and does not reflect every MSA that we have entered into or may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different than those described here.

Employees

As of February 23, 2018, we have 6,274 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 our services, there can be extreme competition amongst employers to attract skilled workers, which often results in a shortage of qualified employees. Additionally, in our Well Support Services segment we are currently experiencing 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.

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.

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.

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 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 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. 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 liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to 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.

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. The 2015 rule was previously stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule and announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction. Recently, in January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction to hear challenges to the 2015 rule resides with the federal district courts; consequently, the previously-filed district court cases will be allowed to proceed. Following the Supreme Court’s decision, the EPA and the Corps issued a final rule in January 2018 staying implementation of the 2015 rule for two years. As a result of these recent developments, future implementation of the June 2015 rule is uncertain. 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 (“NSPS”) and Maximum Achievable Control Technology (“MACT”) standards are expected to be 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. States have the opportunity to submit new air quality monitoring to EPA prior to EPA finalizing any nonattainment designations. 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. In addition, in 2012, the EPA issued federal regulations requiring the reduction of volatile organic compound (“VOC”) emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further requiring that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels.

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, 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. 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. 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. 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, but the BLM issued a rule in December 2017 staying the requirements of its methane rule for one year. BLM’s actions have been challenged in federal court. 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 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. Finally, it should be noted that some 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 the following actions 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. 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. 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.

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.

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, including current natural gas storage capacity and usage;


•	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;


•	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.

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 2016, NYMEX crude oil prices reached a high of $54.06 per barrel and a low of $26.21 per barrel, and during 2017 NYMEX crude oil prices ranged from $42.53 to $60.42 per barrel. In line with the sustained weakness and volatility in oil prices over the course of 2016, we experienced a significant decline in drilling, completion and production activities across our customer base, which resulted in reduced demand and increased competition and pricing pressure to varying degrees across our service lines and operating areas.

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.

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. If we are unable to generate sufficient cash flows or to obtain additional capital 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 Amended Credit Facility (as defined below). 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.

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 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.

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.

We may be unable to implement price increases or maintain existing prices on our core services.

We generate revenue from our core service lines, the majority of which is 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.

We may not be able to service our debt obligations in accordance with their terms.

On January 6, 2017, we entered into a new revolving credit and security agreement (the “New Credit Facility”). We subsequently amended and restated the New Credit Facility in full pursuant to an amended and restated revolving credit and security agreement (the “Amended Credit Facility”) on May 4, 2017. Our ability to meet our debt service obligations under, and comply with the financial covenants contained in, our Amended 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 Amended 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 Amended 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 Amended 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 Amended Credit Facility could require us to repay that portion of indebtedness that exceeds the new borrowing base under our Amended Credit Facility earlier than anticipated, which could adversely impact our liquidity.

Our Amended Credit Facility allows us to borrow amounts up to the lesser of $200 million and a borrowing base based on the value of our accounts receivable and inventory. Currently, our borrowing base is $178.5 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 Amended Credit Facility and could result in a redetermination, and potentially a reduction, of our borrowing bases under our Amended Credit Facility. If our Amended Credit Facility eventually becomes fully drawn, any reduction in the borrowing bases could require us to make mandatory prepayments under our Amended Credit Facility to the extent existing indebtedness under the Amended Credit Facility exceeds the borrowing base. We may have insufficient cash on hand to be able to make mandatory prepayments under our Amended Credit Facility. Any failure to repay indebtedness in excess of our borrowing bases in accordance with the terms of the Amended Credit Facility would constitute an event of default under the Amended 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.

We are subject to restrictive covenants in our Amended Credit Facility, which may restrict our operational flexibility.

The Amended 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 Amended 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 Amended 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 Amended Credit Facility” in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information about the Amended Credit Facility, including the financial and other restrictive covenants contained therein.

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

Our business is capital intensive and we may seek to raise debt capital to fund our business and growth strategy. Indebtedness could have negative consequences that could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects, such as:


•	requiring us to dedicate a substantial portion of our cash flow from operating activities to payments on our indebtedness, thereby reducing the availability of cash flow to fund working capital, capital expenditures, research and development efforts, potential strategic acquisitions and other general corporate purposes;


•	limiting our ability to obtain additional financing to fund growth, working capital or capital expenditures, or to fulfill debt service requirements or other cash requirements;


•	increasing our vulnerability to economic downturns and changing market conditions;


•	placing us at a competitive disadvantage relative to competitors that have less debt;


•	to the extent that our debt is subject to floating interest rates, increasing our vulnerability to fluctuations in market interest rates; and


•	preventing our ability to buy back our common stock or pay cash dividends.

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 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.

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, 2017, we reported consolidated federal NOL carryforwards of approximately $1.1 billion. 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 a subsequent ownership change occurred on or about June 30, 2017 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 2 - 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”). The consummation of the Restructuring Plan occurred in 2017, and any estimates around the related fair market value, the potential for CODI and any associated tax attribute reduction as determined by the Code will not be finalized until the 2017 tax return is filed in 2018. Our estimates are subject to change throughout this period.

We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers.

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.

Reliance upon a few large customers may adversely affect our revenue and operating results.

Our top ten customers represented approximately 40.7%, 46.0% and 53.6% 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.

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 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 the rapid growth that we have experienced, 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; and


•	ability to maintain the level of focused service attention that we have historically been able to provide to our customers.

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 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.

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 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 will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. 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.

Weather conditions could materially impair our business.

Our operations may be adversely affected by severe weather events and natural disasters. Furthermore, our customers’ operations may be adversely affected by seasonal weather conditions. 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 severe 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.

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 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.

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 including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain preconstruction and operating permit reviews for GHG emissions from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of GHGs from specified GHG emission sources, including, among others, certain oil and natural gas production facilities, on an annual basis. More recently, in June 2016, the EPA finalized regulations under the Clean Air Act that address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and also imposes leak detection and repair requirements on operators. However, in June 2017 the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-consider the entirety of the 2016 methane standards. The EPA has not yet published a final rule and, as a result, the 2016 rule remains in effect, but the future implementation of that rule is uncertain at this time. The BLM finalized similar rules in November 2016 that 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. However, in December 2017, BLM finalized a suspension of certain requirements of the rule until January 17, 2019. That suspension is now being challenged in court, and substantial uncertainty exists with respect to implementation of the rule.

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. 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. In August 2017, the United States issued formal notice that it was withdrawing from the Paris Agreement. The Paris Agreement has a four year exit process but the United States’ adherence to this process is uncertain at this time.

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. 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, some 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. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address 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 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 EPA proposes rulemaking for revised oil and gas regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021.

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 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.

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 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.

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.

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 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, 2017, 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.

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.

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.

Our operations are becoming increasingly dependent on digital technologies and services. We use these technologies for internal purposes, including data storage, processing, and transmissions, as well as in our interactions with customers and suppliers. Digital technologies are subject to the risk of cyber-attacks and other cyber incidents. 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. In addition, these risks could have a material adverse effect on our business, results of operations and financial condition.

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 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 68,465,637 shares were outstanding as of February 23, 2018. 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, 1,132,697 shares are issuable pursuant to outstanding restricted stock awards and 92,332 shares are issuable pursuant to outstanding performance shares. In addition, as of February 23, 2018, warrants to purchase up to 3,528,074 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. 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.

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 Amended 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. In addition, we own or lease numerous other smaller facilities and administrative offices across the geographic regions in which we operate, including local sales offices and temporary facilities to house employees in regions where infrastructure is limited. Our leased properties are subject to various lease terms and expirations.

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.

The following table shows our active owned and leased properties, categorized by geographic region as of December 31, 2017.



Region	Administrative and Sales Offices; Research and Technology Facilities	Operational Field Services Facilities
West Texas
Owned	1	38
Leased	4	25
South Texas / South East
Owned	2	21
Leased	9	7
Rockies / Bakken
Owned	—	8
Leased	2	18
California
Owned	—	9
Leased	1	15
Mid-Con
Owned	—	16
Leased	9	13
North East
Owned	—	—
Leased	1	11
Canada
Owned	—	—
Leased	1	—
Total	30	181

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 C&P Business facility in Williston, North Dakota on October 3, 2014 prior to the Predecessor’s acquisition of the C&P Business in 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.

Shareholder Litigation

In July 2014, following the announcement that Old C&J, Nabors, and the Predecessor had entered into the Nabors merger agreement (the “Nabors Merger Agreement”), a putative class action lawsuit was filed by a purported shareholder of Old C&J challenging the Nabors Merger. The lawsuit is styled City of Miami General Employees’ and Sanitation Employees’ Retirement Trust, et al. v. Comstock, et al.; C.A. No. 9980-CB, in the Court of Chancery of the State of Delaware, filed on July 30, 2014 (the “Shareholder Litigation”). The plaintiff in the Shareholder Litigation generally alleged that the Old C&J board of directors breached their fiduciary duties of loyalty and care by approving the Nabors Merger at an allegedly unfair price and through an allegedly unfair process. On November 24, 2014, the Court of Chancery preliminarily enjoined Old C&J from holding its stockholder meeting to approve the Nabors Merger Agreement for a period of 30 days (the “Injunction Order”), but

the Delaware Supreme Court reversed the Injunction Order on December 17, 2014. After the Nabors Merger closed, the plaintiff filed an Amended Verified Class Action Complaint (the “Amended Complaint”), adding various allegations and seeking money damages instead of injunctive relief.

On August 24, 2016, the Court of Chancery granted the defendants’ motions to dismiss the Amended Complaint in its entirety issued its opinion and also granted Old C&J’s motion to recover damages arising from the Injunction Order. On March 23, 2017, the Supreme Court issued an order affirming the Court of Chancery’s opinion.

Plaintiff then filed a motion for attorneys’ fees and costs. On Tuesday, January 23, 2018, the Court of Chancery denied Plaintiff’s motion for attorneys’ fees and costs.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Price of and Dividends on the Registrant’s Common Equity and Related Shareholder Matters

Our common shares are traded on the NYSE under the symbol “CJ.” As of February 27, 2018, we had 68,465,637 common shares issued and outstanding, held by approximately 37 registered holders. The number of registered holders does not include holders that have common shares held for them in “street name,” meaning that the shares are 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 shares that hold such shares in “street name” are not.

The following table sets forth the high and low sales prices of our common shares as reported by the NYSE for the periods indicated:



	High		Low
Period from March 6, 2017 to March 31, 2017	$	41.00	$	32.49
Quarter ended June 30, 2017	$	37.49	$	28.17
Quarter ended September 30, 2017	$	35.07	$	24.70
Quarter ended December 31, 2017	$	35.07	$	24.92

From March 6, 2017, through April 12, 2017, the Company’s common stock was traded on the NYSE MKT under the symbol “CJ.” Prior to March 6, 2017, the Company's common stock was not traded on a national securities exchange.

On February 27, 2018, the last reported sales price of our common shares on the NYSE was $24.26 per share.

We have not declared or paid any cash dividends on our common stock. We currently intend to retain all future earnings for the development and growth of our business, 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 Amended 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

On October 25, 2017, the Company entered into the Merger Agreement, providing for the merger of Merger Sub with and into O-Tex, with O-Tex surviving the Merger, and immediately thereafter, the merger of O-Tex with and into another wholly owned direct subsidiary of the Company.

On the Closing Date, each holder of O-Tex Shares (as defined above) had its O-Tex Shares (excluding any O-Tex Shares held in the treasury of O-Tex or held by us or Merger Sub immediately prior to the effective time of the Merger) converted into the right to receive such Stockholders’ pro rata portion of the Specified C&J Common Stock (as defined above).

On the Closing Date, in connection with the completion of the Merger, we issued the Specified C&J Common Stock to the Stockholders as described above. The issuance of the Specified C&J Common Stock in the Merger was not registered under the Securities Act. These shares were issued in a private placement exempt from the registration requirements of the Securities Act, in reliance on the exemptions set forth in Section 4(a)(2) of the Securities Act. On December 22, 2017, we filed a registration statement entitling the O-Tex Stockholders to request that we register their Specified C&J Common Stock for sale under the Securities Act at various times and upon the terms and conditions set forth in the Merger Agreement.

Rights Offering, Backstop Commitment Agreement

On December 6, 2016, we entered into a backstop commitment agreement (the “Backstop Commitment Agreement”), pursuant to which certain holders of our unsecured indebtedness as of such date (the “Backstop Parties”) agreed to backstop a $200.0 million cash investment in us pursuant to a rights offering (the “Rights Offering”) conducted in accordance with the Restructuring Plan.

In accordance with the Restructuring Plan, the Backstop Commitment Agreement and the Rights Offering procedures, we offered eligible creditors, including the Backstop Parties, the right to purchase common stock upon emergence from the Chapter 11 Proceeding for an aggregate purchase price of $200 million. The Rights Offering, which commenced on November 15, 2016 and ended on December 9, 2016, provided holders of eligible secured claims under our prior credit agreement as of the record date set therefor to be granted rights entitling each such holder to subscribe to purchase an amount of common stock (such common stock offered for purchase pursuant to the Rights Offering, the “Rights Offering Shares”) up to such holders’ respective pro rata share of such eligible secured claims at a per share price of $13.58. Under the Backstop Commitment Agreement, the Backstop Parties agreed to purchase, severally and not jointly, the Rights Offering Shares that were not duly subscribed to by parties other than Backstop Parties pursuant to the Rights Offering at the same per share price as the Rights Offering (the “Backstop Commitment”).

We paid the Backstop Parties on the Plan Effective Date a put option premium equal to 5.0% of the $200 million committed amount (the “Put Option Premium”) in the form of common stock at the same per share price offered in the Rights Offering. All amounts paid to the Backstop Parties in their capacities as such for the Put Option Premium were paid pro rata based on the amount of their respective Backstop Commitments. As a condition to the closing of the transactions contemplated by the Backstop Commitment Agreement, we entered into a Registration Rights Agreement with the Backstop Parties entitling such Backstop Parties to request that we register their securities for sale under the Securities Act at various times and upon the terms and conditions set forth in the Registration Rights Agreement.

New Common Stock

On the Plan Effective Date, pursuant to the terms of the Restructuring Plan, we issued an aggregate of 55,463,903 shares of common stock to the Holders of Allowed Secured Lender Claims (as defined in the Restructuring Plan). We also issued 1,180,083 warrants (subject to adjustments pursuant to the terms of the Warrants) at an initial exercise price of $27.95 per warrant (subject to adjustments pursuant to the terms of the Warrants) to former holders of Interests in our Predecessor and will issue in the future up to an additional 2,360,166 warrants (subject to adjustments pursuant to the terms of the Warrants) at an initial exercise price of $27.95 per warrant (subject to adjustments pursuant to the terms of the Warrants) to the Unsecured Claims Representative for the benefit of the former holders of Unsecured Creditor Claims after the Plan Effective Date in accordance with the terms of the Restructuring Plan, the Confirmation Order, the Unsecured Creditor Agreement and the Warrant Agreement.

Of the 55,463,903 shares of common stock issued on the Plan Effective Date,


•	39,999,997 shares of common stock were issued pro rata to certain holders of claims arising under our Predecessor's prior credit agreement (the “Plan Shares”);


•	14,408,789 shares of common stock were issued to participants in the Right Offering at a per share purchase price of $13.58, for an aggregate purchase price of approximately $195.7 million (the “Rights Offering Shares”);


•	318,743 shares of common stock were issued to the Backstop Parties under the Backstop Parties’ commitment to purchase Unsubscribed Shares (as defined in the Backstop Commitment Agreement) at a per share purchase price of $13.58, for an aggregate purchase price of approximately $4.3 million (the “Backstop Shares”); and


•	736,374 shares of common stock were issued to the Backstop Parties as the Put Option Premium (as defined in the Backstop Commitment Agreement) under the Backstop Commitment Agreement, representing 5.0% of the $200 million committed amount and a per share purchase price of $13.58 (the “Put Option Shares”).

The Warrants, Plan Shares, Rights Offering Shares and Put Option Shares were issued pursuant to an exemption from the registration requirements of the Securities Act under Section 1145 of the Bankruptcy Code. The Backstop Shares were issued pursuant to the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) thereof.

Purchases of Equity Securities by the Issuer or Affiliated Purchasers

Repurchases of Equity Securities

The following table summarizes stock repurchase activity for the fiscal year ended December 31, 2017 (in thousands, except average price paid per share). All of the repurchases below are the Successor common stock that were

withheld to satisfy tax withholding obligations of employees that arose upon the vesting of restricted stock. The value of such stock is based on the closing price of the Successor common stock on the vesting date. No shares of stock were purchased as part of a publicly announced program.



	Total Number of Shares Purchased (a)	Average Price Paid Per Share
January 1—January 31	—	$	—
February 1—February 28	107,336	43.93
March 1—March 31	—	—
April 1—April 30	—	—
May 1—May 31	—	—
June 1—June 30	—	—
July 1—July 31	—	—
August 1—August 31	—	—
September 1—September 30	—	—
October 1—October 31	—	—
November 1—November 30	—	—
December 1—December 31	—	—

(a) 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.

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
	Year Ended December 31,		Years Ended December 31,
	2017		2016			2015			2014		2013

	(In thousands except per share amounts)		(In thousands except per share amounts)
Revenue	$	1,638,739	$	971,142		$	1,748,889		$	1,607,944	$	1,070,322
Net income (loss)	$	22,457	$	(944,289	)	$	(872,542	)	$	68,823	$	66,405
Net income (loss) per common share
Basic	$	0.37	$	(7.98	)	$	(8.48	)	$	1.28	$	1.25
Diluted	$	0.37	$	(7.98	)	$	(8.48	)	$	1.22	$	1.20
Total assets	$	1,608,857	$	1,361,682		$	2,198,991		$	1,612,746	$	1,132,300
Long-term debt and capital lease obligations, excluding current portion	$	—	$	—		$	1,108,123		$	349,875	$	164,205

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.

Introductory Note and Corporate 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 (as defined below), “C&J” or the “Company”) is a leading provider of well construction, well completion, well support and other complementary oilfield services to oil and gas exploration and production (“E&P”) companies throughout the continental United States. We offer a comprehensive, integrated suite of services throughout the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, directional drilling, rig services, fluids management, artificial lift and other completion and specialty well site support services. We are headquartered in Houston, Texas and operate across all active onshore basins in the continental United States.

Business Overview

The O-Tex Transaction

Stockholder became entitled to receive a pro rata portion of $90.8 million in cash. The cash portion of the merger consideration was determined based on $132.5 million of base cash merger consideration, which was subject to closing adjustments as provided in the Merger Agreement (including reductions for the repayment of O-Tex’s indebtedness and transaction expenses) and may be further adjusted post-closing as provided in the Merger Agreement (including reductions for the payment of certain amounts into escrow for post-closing working capital adjustments and the satisfaction of post-closing indemnification obligations).The foregoing description of the Merger Agreement does not purport to be complete and is qualified in its entirety by reference to the Merger Agreement, which was filed as Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on October 26, 2017 and is incorporated herein by reference.

Canadian Well Support Service Divestiture

Our Reportable Business Segments

As of December 31, 2017, our reportable business segments were:


•	Completion Services, which consists of the following businesses and service lines: (1) fracturing; (2) cased-hole wireline and pumping services; (3) well construction & intervention services, which includes cementing, coiled tubing and directional drilling services; and (4) completion support services, which includes our R&T department and data control instruments business.


•	Well Support Services, which consists of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) special services, which includes plug and abandonment, artificial lift applications and other specialty well site services.

Our reportable business segments are described in more detail below; for financial information about our reportable business segments, including revenue from external customers and total assets by reportable business segment, please see “Note 13 - 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 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. Our well construction & intervention services business, which includes cementing, coiled tubing and directional drilling services, and our completion support services business, which includes the manufacturing capabilities of our R&T department and data control instruments business, are each also managed through our Completion Services segment. The majority of revenue for this segment is generated by our fracturing business.

During the fourth quarter of 2017, our fracturing business deployed, on average, approximately 590,000 hydraulic horsepower (“HHP”) out of our fleet of approximately 860,000 HHP as of December 31, 2017. We ended the year with 615,000 HHP deployed over 14 horizontal and two vertical fleets. With the delivery and deployment of an additional 40,000 new HHP in February 2018, our current total capacity is 900,000 HHP. In our cased-hole wireline and pumping business, we deployed, on average, approximately 75 of our average fleet of 124 wireline trucks, as well as all 68 of our pumpdown units. In our well construction & intervention services business, we deployed, on average, approximately 16 coiled tubing units out of our average fleet of approximately 44 units. Prior to the completion of the O-Tex Transaction, in our legacy cementing services business, we deployed, on average, approximately 31 cementing units out of our average fleet of 36 units. After the completion of the O-Tex Transaction, we deployed, on average, approximately 56 cementing units out of our average fleet of 81 units during the month of December. 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.

Management evaluates the operational performance of our Completions Services segment and allocates resources primarily based on Adjusted EBITDA because management believes that Adjusted EBITDA provides important information about the activity and profitability of our lines of business within this segment. Adjusted EBITDA is a non-GAAP financial measure computed as total earnings (loss) before net interest expense, income taxes, depreciation and amortization, other income (expense), net, net gain or loss on disposal of assets, acquisition-related costs, and non-routine items.

For the year ended December 31, 2017, revenue from our Completion Services segment was $1.3 billion, representing approximately 76.7% of our total revenue, compared with revenue of $599.8 million for the year ended December 31, 2016, which represents a 109.5% year-over-year increase. Adjusted EBITDA from this segment for the year ended December 31, 2017 was $221.9 million, compared with $(41.6) million of Adjusted EBITDA for the year ended December 31, 2016, which

represents a 633.1% year-over-year increase.



	Successor		Predecessor
	Year Ended December 31,
	2017		2016

Revenue
Fracturing	$	777,147	$	353,929
Wireline & Pumping Services	315,999		159,317
Other (Cementing, Coil, Directional Drilling and Research & Technology)	163,365		86,541
Total revenue	$	1,256,511	$	599,787

Adjusted EBITDA	$	221,888	$	(41,624	)

Average active hydraulic fracturing horsepower	515,000		480,000
Total fracturing stages	15,189		11,413

Average coiled tubing units	44		45
Average active coiled tubing units	19		27

Average active wireline trucks	72		68

Average active pumpdown units	61		44

Please read Note 13 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report, for a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure (in thousands) on a reportable segment basis for the years ended December 31, 2017 and 2016.

In our Completion Services segment, we continued to experience strong customer demand for all of our core services, which resulted in sequential improvement in both revenue and profitability despite year-end seasonality. In our fracturing business, we deployed a refurbished horizontal frac fleet to a dedicated customer in the Mid-Continent in early December 2017, which resulted in approximately 615,000 HHP deployed at quarter end consisting of fourteen horizontal and two vertical frac fleets. We also experienced solid customer demand and improved pricing in our wireline and pumping businesses, offset by varying degrees of year-end seasonality as certain core customers either substantially reduced activity levels or deferred certain jobs into the first quarter of 2018. With respect to our wireline business, our Texas districts continued to outperform, delivering an almost 13.0% increase in revenue that enhanced fourth quarter profitability and offset seasonal revenue declines in other core basins. In our well construction and intervention services business, our fourth quarter financial performance benefited from the closing of the O-Tex Transaction. Additionally, our cementing services business continued to experience growing demand and improved utilization in our core West Texas operating basin as we were awarded more rigs from both new and existing customers. In our coiled tubing business, despite fourth quarter seasonality, utilization and pricing continued to improve due to tight market conditions for large diameter units and our recently signed agreements for dedicated units with some of our most active customers in both South and West Texas. Demand for large diameter units remains strong, and we are currently evaluating additional dedicated agreements with select customers for our two new-build units that we expect to be delivered early in the second quarter of 2018.

Completion Services Outlook

As we move through the first quarter of 2018, we currently expect that our Completion Services segment will continue to experience strong activity levels based on increasing demand for our products and services as customer budgets were refreshed and new production targets set early in the first quarter. Based on customer demand in our fracturing business, we expect to deploy an additional horizontal fleet, consisting of new-build pumps and refurbished ancillary equipment, to a dedicated customer by the end of the first quarter. This will result in us exiting the first quarter of 2018 with approximately 655,000 HHP deployed, consisting of fifteen horizontal and two vertical fracturing fleets. We also currently expect to deploy all of our additional refurbished equipment by year-end 2018 due to continued strong near-term outlook. In our cased-hole wireline and pumping business, we expect to deploy refurbished pumping units and previously stacked wireline trucks into

service during the first quarter as customers continue to increase completion activity and we continue to seek to align ourselves with our most efficient customers with competitive pricing.

In our cementing business, we expect to focus on increasing utilization by fully integrating the O-Tex asset base and redeploying warm stacked units at market pricing. We expect the majority of asset redeployment and improvement in utilization to occur in West Texas where demand remains strong, but we anticipate gradual improvement in our other core operating basins by the end of the first quarter as the chance for potential disruptions caused by inclement weather decreases. We ordered two large diameter, meaning two inches or larger in diameter, new-build coiled tubing units to meet strong demand from multiple customers, which are expected to be deployed to customers early in the second quarter of 2018. With the arrival of these new units combined with strengthening market conditions, we expect to continue with our strategy of dedicating additional units to our most active customers at elevated utilization levels and market pricing. We have and expect to continue to experience increases in activity and pricing in all of our core operating basins.

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, and special services, including artificial lift applications and other specialty well site services. The majority of revenue for this segment is generated by our rig services business, and we consider rig services and fluids management to be our core businesses within this segment.

During the fourth quarter of 2017, our rig services business deployed, on average, approximately 121 workover rigs per workday out of our average fleet of approximately 400 marketable workover rigs. In our fluids management business, we deployed, on average, approximately 628 fluid services trucks per workday and approximately 1,114 frac tanks per workday out of our estimated average fleets of approximately 1,087 trucks and 3,744 frac tanks, respectively. In our fluids management business, we own 25 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. Additionally, in response to the continued competitive landscape, we have continued to focus on operational rightsizing measures to better align these businesses with current market conditions, which has included closing facilities and idling unproductive equipment.

Management evaluates the operation and performance of our Well Support Services segment and allocates resources primarily based on activity levels, specifically rig and trucking hours, as well as Adjusted EBITDA. The following table presents rig and trucking hours for our Well Support Services for the years ended December 31, 2017 and 2016 (in thousands):



	Successor		Predecessor
	Year Ended December 31,
	2017		2016

Revenue
Rig Services	$	218,819	$	197,003
Fluids Management Services	122,949		132,486
Other Well Support Services (includes ESPCT)	40,460		34,279
Total revenue	$	382,228	$	363,768

Adjusted EBITDA	$	9,233	$	19,456

Average active workover rigs	188		197
Total workover rig hours	452,948		429,727

Average fluids management trucks	1,107		1,411
Average active fluids management trucks	638		725
Total fluids management truck hours	1,281,024		1,384,897

During the fourth quarter of 2017, Well Support Services segment revenue decreased sequentially primarily due to the sale of our Canadian rig services business in early November 2017 and the typical year-end seasonal slowdown. However, we improved segment profitability by executing on improving demand in select core basins and obtaining higher overall pricing for our services, even with an additional $1.6 million of inventory write-downs in our artificial lift business. In our rig services business, we continued to capitalize on high-grading our customer base and reallocating assets to areas with improving demand and higher overall pricing. In West Texas, despite a seasonally-driven decline in workover rig and trucking activity, revenue increased nearly 4.0% driven by plug and abandonment, frac tank rentals and special services. Additionally, our special services business experienced improved revenue and profitability due to higher activity levels in California. As oil prices increased, we continued with our strategy of selectively deploying equipment with customers that plan to increase workover or well maintenance activities in our core operating basins. In our fluids management business, improving activity levels primarily in West Texas and the Mid-Continent resulted in higher pricing and sequential improvement in both revenue and profitability. However, our ability to fully capitalize on those opportunities was limited due to a lack of skilled labor, and we believe that pricing will need to further increase in order to both attract and retain additional personnel to meet improving demand for fluids management services as production levels continue to increase.

Well Support Services Outlook

As we move through the first quarter of 2018, we currently expect that our Well Support Services segment will experience higher activity levels and improving profitability. We expect that improving oil prices and workover economics will result in increased workover activity levels allowing us to continue our strategy of high-grading our customer base and reallocating assets into areas with higher pricing and profitability. In our fluids management business, we expect to continue to focus on putting personnel and equipment to work in areas with improving demand, such as West Texas, and the Mid-Continent. However, labor will continue to be an impediment and we plan to increase our rates commensurate with our rising cost structure to generate more attractive returns. We expect our fluids management business to continue to face competition from growing infrastructure build-out, and any future asset deployment will also be limited by our ability to raise rates to attract and retain skilled workers. We are encouraged to see signs of market improvement for our Well Support Services segment, and our primary goal remains to align ourselves with customers that value our ability to deliver superior service quality safely and to increase segment profitability.

Other Services

Our Other Services segment consisted of smaller, non-core business lines that have since been divested, including our specialty chemical business, equipment manufacturing and repair business and the Company's international coiled tubing operations in the Middle East. In line with the discontinuance of these small, ancillary service lines and divisions, subsequent to the year ended December 31, 2016, we are now disclosing two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period.

Our Other Services segment contributed $7.6 million of revenue for the year ended December 31, 2016, which represents approximately 0.8% of our total revenue. Adjusted EBITDA from this segment for the year ended December 31, 2016 was $(5.8) million.

Please read Note 13 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report, for a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure (in thousands) on a reportable business segment basis for the year ended December 31, 2016.

Operating Overview & Strategy

Our results of operations in our core service lines are driven primarily by four 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, 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 products 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 service performance.

Our operating strategy is focused on maintaining high asset utilization levels to maximize revenue generation while controlling cost 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 efficiency gains are central to our efforts to support utilization and grow our business. However, asset utilization is not necessarily indicative of our financial and/or operational performance and should not be given undue reliance. 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 as a group. 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 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. 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.”

Management evaluates the performance of our reportable business segments primarily based on Adjusted EBITDA because management believes Adjusted EBITDA provides important information about the activity and profitability of our lines of business within each reportable business segment and aids us in analytical comparisons for purposes of, among other things, efficiently allocating our assets and resources. Our management team also monitors asset utilization, among other factors, for purposes of assessing our overall activity levels and customer demand. In 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 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 Support Services segment, we measure activity levels primarily by the number of hours our assets work on a monthly basis, based on the available working days per month. However, given the variance 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, asset utilization cannot be relied on as indicative of our financial or operating performance. For additional information, please see “Our Reportable Business Segments” in this Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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 the 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 general domestic and international economic conditions, 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, and other factors that are beyond our control.

In light of the above, demand for our services tends to be extremely volatile and cyclical, as 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 expenditures depends largely upon prevailing industry conditions that are influenced by numerous factors which are beyond our control, including, among other things, current and expected future levels of oil and gas prices and the perceived stability and sustainability of those prices, which, in turn, is driven primarily by the supply of, and demand for, oil and gas. Oil and gas prices, and therefore the level of drilling, completion and workover activity by our customers, historically have been extremely volatile and are expected to continue to be highly volatile.

In late 2014, oil prices began a substantial and rapid decline, and the severe weakness continued throughout 2015 and the majority of 2016. As we entered 2016, we experienced a sharp drop in activity across our customer base as operators reacted to further declines in oil prices and the deteriorating onshore drilling rig count. The consequent negative impact on the level of drilling, completion and production activity and capital expenditures by our customers adversely affected the demand for our services throughout the severe industry downturn. Our financial and operational performance were significantly impacted, which led to the Chapter 11 Proceeding. Although both crude oil and natural gas prices began to increase modestly and stabilize in late 2016, commodity prices, in general, have remained significantly lower than the industry average experienced leading up to the downturn. Crude oil prices have rebounded from the lows set in early 2016, and in 2017 prices have averaged approximately $51.00 per barrel. Natural gas prices declined significantly in 2009 and have remained depressed relative to pre-2009 levels. Although there has been slight improvement in the early part of 2018, commodity prices continue to be relatively unstable and any declines or perceived sustained weakness impacts the allocation of capital by our customers.

Sustained weakness in oil and gas prices influences our customers to curtail their operations, reduce their capital expenditures, and request pricing concessions to reduce their operating costs. The demand for drilling, completion and workover services is driven by available investment capital for such activities and in a lower oil and gas price environment, demand for service and maintenance generally decreases as oil and gas producers decrease their activity and 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. A prolonged low level of customer activity, such as we experienced through 2015 and 2016, could adversely affect our financial condition and results of operations.

Competition and Demand for Our Services

We operate in highly competitive areas of the oilfield services industry with significant potential for excess capacity. Completion and well servicing 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 such equipment in any particular area. Utilization and pricing for our services have in the past been negatively affected by increases in supply relative to demand in our core operating areas and geographic markets.

Additionally, 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 over the course of 2015, and for the majority of 2016, and the consequent negative impact on the level of drilling, completion and production activity and capital expenditures by our customers, adversely affected the demand for our services. This, in turn, negatively impacted our ability to maintain adequate utilization of our asset base and to negotiate pricing at levels generating sufficient margins. Moreover, the impact to our financial and operational performance ultimately led to the Chapter 11 Proceeding.

Our revenues and earnings 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. 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 costs increase, could have a material adverse effect on our business, financial position and results of operations.

greater resources could allow them to compete more effectively than we can, including by reducing prices for services in our core operating areas. Our major competitors for our Completion Services include Halliburton, Schlumberger, BJ Services, Keane Group, RPC, Inc., FTS International, Inc. (formerly known as Frac Tech Services), 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, Ranger Energy Services, Precision, Forbes and Pioneer 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, 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 commodity prices such as those we experienced from late 2014 through the majority of 2016. Throughout this severe, prolonged downturn for our industry, our customer base demonstrated a more intense focus and placed a higher priority on receiving the lowest service cost pricing possible. Additionally, projects for certain of our core service lines are often awarded on a bid basis, which tends to further increase competition based primarily on price. During this downturn, our utilization and pricing levels were also negatively impacted by predatory pricing from certain large competitors, who elected to operate at negative margins for these services.

During healthier market conditions, we believe many of our customers choose to work with us based on the safety, performance and quality of our crews, equipment and services, although even then, we must 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, coupled with superior execution and operating efficiency. As part of this strategy, 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.

Current Market Conditions and Outlook

The challenging market conditions experienced from late 2014 through the majority of 2016 began to abate towards the end of 2016 as commodity prices began to stabilize and customers began re-initiating their drilling and completion programs. As we entered 2017, we experienced increasing utilization levels in our Completion Services segment as our customers accelerated drilling and completion activity to take advantage of higher overall commodity prices. We were able to increase pricing across our core Completion Services businesses, largely due to a lack of available service capacity in select core operating basins and rapidly increasing demand. Stability in the North American land drilling rig count coupled with the continued shortage of available fracturing equipment over the second half of 2017 resulted in higher overall utilization and pricing across our entire Completion Services segment, especially in our cased-hole wireline and pumping, coiled tubing and cementing businesses. During the fourth quarter of 2017, we continued to experience strong demand for all of our core completion services, which resulted in improved financial performance primarily due to additional equipment deployment and increased pricing despite the seasonal slowdown in activity in select operating basins. We currently expect demand to remain strong for our core completion services through 2018.

In our Well Support Services segment, we also experienced improvement in market conditions entering into 2017, as customers began to allocate more capital towards well maintenance and workover activities with the stabilization in commodity prices. However, even with the increased activity levels experienced early in 2017, the operating environment remained highly competitive as several of our major competitors did not increase service rates throughout the majority of the year. In the fourth quarter of 2017, we closed the Canadian Divestiture narrowing our focus exclusively on the lower forty-eight U.S. land market. Additionally, despite the expected seasonal slowdown in activity experienced in the fourth quarter, we began to see signs of modest improvement in select core basins, especially in our special services and fluids management businesses. Increases in plug and abandonment, rental and fishing activities in both California and West Texas resulted in a sequential increase in both revenue and profitability in our special services business as well. In our fluids management business, we experienced pockets of activity improvement, specifically in West Texas and the Mid-Continent, but struggled to capitalize on these opportunities primarily due to growing labor shortages. We believe that pricing will need to further improve in order to both attract and retain additional employees to meet growing demand for fluids management services as completion activity continues to increase.

Based on market conditions and customer demand, we are optimistic about the level of completion activity in 2018. Assuming macroeconomic conditions and commodity prices remain stable or improve, we would expect improving

levels of activity from the majority of our customer base in 2018, which should result in continued operational and financial improvement in both our Completion Services segment and Well Support Services segment.

We are actively monitoring the market and managing our business in line with demand for services, and we will make adjustments to our strategy as necessary to effectively respond to changes in market conditions. We are taking a measured approach to asset deployment, balancing our view of customer demand with an acute focus on generating positive returns for our shareholders. Our top priorities remain to drive revenue by maximizing utilization, to improve margins through cost control, and to protect and grow market share by focusing on the quality and efficiency of our service execution and ensuring that we are strategically positioned to capitalize on future market improvement.

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.

Results of Operations

As a result of our emergence from the Chapter 11 Proceeding, the 2017 financial results have been separately presented under the label "Successor" for the year ended December 31, 2017. 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.

The following is a comparison of our results of operations for the year ended December 31, 2017, compared to the year ended December 31, 2016, and a comparison of our results of operations for the year ended December 31, 2016, compared to the year ended December 31, 2015. Our results for the 2017 and 2016 years include the financial and operating results of the businesses acquired in the Nabors Merger for the entire period. Our results for the 2015 year include the financial and operating results of the businesses acquired in the Nabors Merger for the partial period beginning March 24, 2015 (the "Merger Effective Time") through December 31, 2015. Accordingly, comparisons of the 2016 results to prior year 2015 results may not be meaningful.

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
Completion Services:
Revenue	$	1,256,511		$	599,787		$	656,724
Operating income (loss)	$	137,014		$	(306,614	)	$	443,628

Well Support Services:
Revenue	$	382,228		$	363,768		$	18,460
Operating income (loss)	$	(21,584	)	$	(377,707	)	$	356,123

Other Services:
Revenue	$	—		$	7,587		$	(7,587	)
Operating income (loss)	$	—		$	(51,778	)	$	51,778

Corporate / Elimination:
Operating income (loss)	$	(131,209	)	$	(133,909	)	$	2,700

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

Reorganization items	—			55,330			(55,330		)
Income tax benefit	(39,760		)	(129,010		)	89,250
Net income (loss)	$	22,457		$	(944,289	)	$	966,746

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 $656.7 million of revenue in our Completion Services segment as 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 $18.5 million in our Well Support Services segment as a result of improvement in both our rig services and special services product lines and partially 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 Service segment. Revenue has been positively impacted by overall increased utilization levels across our Completion Services and Well Support Services segments resulting 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, (iii) a $3.8 million increase in acquisition related costs related to the O-Tex acquisition and (iv) a $1.2 million increase in other general and administrative expenses, 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.

We also incurred $6.4 million in R&D for the year ended December 31, 2017, as compared to $7.7 million for the corresponding prior year period. The decrease in R&D was primarily due to our cost control initiatives, which included scaling back our R&T business line and initiatives and delaying certain projects.

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

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.

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.

Results for the Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

The following table summarizes the change in our results of operations for the year ended December 31, 2016, compared to the year ended December 31, 2015 (in thousands):



	Years Ended December 31,
	2016			2015			$ Change
Completion Services:
Revenue	$	599,787		$	1,261,398		$	(661,611	)
Operating income (loss)	$	(306,614	)	$	(882,786	)	$	576,172

Well Support Services:
Revenue	$	363,768		$	459,265		$	(95,497	)
Operating income (loss)	$	(377,707	)	$	(31,253	)	$	(346,454	)

Other Services:
Revenue	$	7,587		$	28,226		$	(20,639	)
Operating income (loss)	$	(51,778	)	$	(69,129	)	$	17,351

Corporate / Elimination:
Operating income (loss)	$	(133,909	)	$	(115,154	)	$	(18,755	)

Combined:
Revenue	$	971,142		$	1,748,889		$	(777,747	)
Costs and expenses:
Direct costs	947,255			1,523,194			(575,939		)
Selling, general and administrative expenses	229,267			239,697			(10,430		)
Research and development	7,718			16,704			(8,986		)
Depreciation and amortization	217,440			276,353			(58,913		)
Impairment Expense	436,395			791,807			(355,412		)
Loss on disposal of assets	3,075			(544		)	3,619
Operating income	(870,008		)	(1,098,322		)	228,314
Other income (expense):
Interest expense, net	(157,465		)	(82,086		)	(75,379		)
Other income (expense), net	9,504			8,773			731
Total other expenses, net	(147,961		)	(73,313		)	(74,648		)
Income before income taxes	(1,017,969		)	(1,171,635		)	153,666
Reorganization items	55,330			—			55,330
Income tax expense	(129,010		)	(299,093		)	170,083
Net income	$	(944,289	)	$	(872,542	)	$	(71,747	)

Revenue

Revenue decreased $777.7 million, or 44.5%, for the year ended December 31, 2016, as compared to the year ended December 31, 2015. The decrease in revenue was primarily due to (i) a decrease of $661.6 million in our Completion Services segment as a result of significantly lower utilization and pricing levels across this segment caused by the extremely competitive market environment given the severe decline in U.S. onshore drilling and completion activity, partially offset by the fact that Completion Services revenue for the corresponding prior year period only included the Nabors Merger completion and production services business (the "C&P Business") revenue from the Merger Effective Time to December 31, 2015. The $95.5 million decrease in revenue in our Well Support Services segment was primarily due to the unprecedented low levels of customer activity during 2016 in areas that typically maintain moderate levels of well support services activity, partially offset by the fact that revenue for the corresponding prior year period only included C&P Business Well Support Services revenue from the Merger Effective Time to December 31, 2015. The $20.6 million decrease in our Other Services segment was primarily due to continued weak demand for our services driven by the low commodity prices characterizing this severe, prolonged industry downturn.

Direct Costs

Direct costs decreased $575.9 million, or 37.8%, to $947.3 million for the year ended December 31, 2016, as compared to $1.5 billion for the year ended December 31, 2015. The decrease in direct costs was primarily due to the corresponding decrease in revenue which was negatively impacted by overall lower utilization levels across our Completion Services and Well Support Services segments resulting from the extremely competitive market environment caused by the severe decline in U.S. onshore drilling and completion activity as well as the unprecedented slowdown in well support services activity, and partially offset by the shorter period for the C&P Business from the date the Nabors Merger was closed to December 31, 2015, as noted above. As utilization fell in our Completion Services segment, we strategically stacked additional equipment, closed unprofitable facilities, reduced head count and aggressively cut costs in order to further lower our operational cost structure. Similarly, in our Well Support Services segment, we exited select service lines in certain basins, closed unprofitable facilities and further reduced head count.

As a percentage of revenue, direct costs increased to 97.5% for the year ended December 31, 2016, up from 87.1% for the year ended December 31, 2015, primarily due to substantially lower pricing for our services due to competitive market conditions resulting from the rapid and sustained decline in commodity prices, partially offset by reductions to our cost structure, as noted above.

Selling, General and Administrative Expenses ("SG&A") and Research and Development Expenses ("R&D")

SG&A decreased $10.4 million, or 4.4%, to $229.3 million for the year ended December 31, 2016, as compared to $239.7 million for the year ended December 31, 2015. The decrease in SG&A was primarily due to a $32.1 million decrease in acquisition-related costs and a $12.6 million decrease in employee related costs as a result of headcount reductions. These amounts are partially offset by $30.4 million in costs related to the Chapter 11 Proceeding and related restructuring activities, by a $2.0 million increase in legal fees and settlements as a result of the Chapter 11 Proceeding and by the fact that SG&A associated with the C&P Business was only incurred from the closing of the Nabors Merger to December 31, 2015.

We also incurred $7.7 million in R&D for the year ended December 31, 2016, as compared to $16.7 million for the corresponding prior year period. The decrease in R&D was primarily due to our cost control initiatives, which included scaling back our R&T business line and initiatives and delaying certain projects.

Depreciation and Amortization Expense ("D&A")

D&A decreased $58.9 million, or 21.3%, to $217.4 million for the year ended December 31, 2016 as compared to $276.4 million for the same period in 2015. The decrease in D&A was primarily the result of significant impairment charges recorded during 2015 and the first half of 2016 due to the steep decline in asset utilization levels related to the sustained downturn in the oil and gas industry.

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 during the third and fourth quarters of 2015 and throughout 2016. Based on our assessment, we recorded impairment expense of $436.4 million for the year ended December 31, 2016, 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.

Impairment expense for the year ended December 31, 2015 was $791.8 million and consisted of $385.0 million of goodwill impairment within each of our Completion Services, Well Support Services and Other Services segments, $393.1 million of PP&E impairment related to the Completion Services and Other Services segments, and $13.7 million related to other intangible assets.

Reorganization items

Interest Expense, net

Interest expense increased $75.4 million, or 91.8%, to $157.5 million for the year ended December 31, 2016. The increase is primarily due to $91.9 million of accelerated amortization of original issue discount and deferred financing costs, which we fully amortized as of June 30, 2016 as a result of our entry into a restructuring support agreement related to our Chapter 11 Proceeding, and due to $3.5 million in interest expense primarily related to higher levels of borrowings under the Revolving Credit Facility and DIP Facility, partially offset by $20.0 million of lower interest expense due to the Chapter 11 Proceeding in that interest expense subsequent to a Chapter 11 filing is recognized only to the extent that it will be paid during the cases or that it is probable that it will be an allowed claim. As a result, we did not accrue interest that we believed was not probable of being treated as an allowed claim in the Chapter 11 Proceeding.

Income Taxes

We recorded an income tax benefit of $129.0 million for the year ended December 31, 2016, at an effective rate of 12.0%, compared to income tax benefit of $299.1 million for the year ended December 31, 2015, at an effective rate of 25.5%. The decrease in the effective tax rate is primarily due to valuation allowances applied against certain deferred tax assets including net operating loss carryforwards. The effective rate, and resulting benefit, is less than the expected statutory rate primarily due to impairment charges that were not deductible for tax, the impact of permanent differences, including non-deductible reorganization costs and the valuation allowance reducing the carrying value of certain deferred tax assets.

Liquidity and Capital Resources

Sources of Liquidity and Capital Resources

Our primary uses of cash are for operating costs and expenditures and capital 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 requirements 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


•	maintenance capital expenditures related to our existing equipment, such as refurbishment and other activities to extend the useful life of partially or fully depreciated assets.

On January 6, 2017, we entered into the New Credit Facility with PNC Bank, National Association, as administrative agent (the “Agent”). We subsequently amended and restated the New Credit Facility in full pursuant to the Amended Credit Facility dated May 4, 2017, with the Agent and the lenders party thereto. We currently have $178.5 million of available borrowing capacity under our Amended Credit Facility after taking into consideration our current outstanding letters of credit of approximately $20.7 million. For additional information about the Amended Credit Facility, please see “-Description of our Indebtedness” below and Note 4 - Debt and Capital Lease Obligations in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

As of December 31, 2017, we had a cash balance of $113.9 million and no borrowings drawn on our Amended Credit Facility resulting in total liquidity of $292.3 million. Under the terms of our Amended Credit Facility, the borrowing base is subject to monthly adjustments based on current levels of accounts receivable and inventory.

Capital expenditures totaled $210.2 million in 2017, primarily pertaining to the maintenance of deployed equipment, the refurbishment of existing stacked equipment in preparation for redeployment and the related reactivation costs, and the building of new equipment for deployment in our core service lines. Based on current market conditions and customer demand, and assuming they remain relatively stable, we expect 2018 capital expenditures to range between approximately $430.0 million and $450.0 million. The majority of our 2018 capital expenditure program is expected to be used for the full refurbishment of all of our remaining stacked fracturing fleets, including the related reactivation costs, which we expect to fully redeploy by year-end, the refurbishment and redeployment of stacked equipment across most of our other core service lines, the deployment of new-build equipment primarily in our Completion Services segment and the ongoing maintenance of our active, deployed equipment.

With the stable North American drilling rig count, higher commodity prices, and the continued shortages of available completion services equipment, we are particularly focused on redeploying our stacked frac fleets. We have been

upgrading and standardizing our equipment concurrent with our reactivation efforts, which among other benefits, is expected to increase the operating life of the equipment and lower the overall cost of ownership over time. During the fourth quarter of 2017, we deployed a refurbished horizontal frac fleet, totaling 40,000 HHP, to a dedicated customer in the Mid-Continent. In the first quarter of 2018, we plan to deploy another horizontal frac fleet consisting of 40,000 HHP of new-build pumps and refurbished ancillary equipment to a dedicated customer. Additionally, we plan to redeploy the remainder of our approximately 245,000 stacked HHP over the course of 2018 at an average estimated capital cost of approximately $24.0 million per horizontal equivalent frac fleet. Our remaining stacked HHP represents our oldest stacked equipment, and thus the most expensive to refurbish and redeploy. This estimated capital cost is inclusive of the pump refurbishment costs and all ancillary equipment necessary for future redeployment. Our typical horizontal fleet size consists of 20 pumps and our typical vertical fleet size consists of 10 pumps. The estimated capital cost to redeploy the remainder of our stacked HHP is inherently uncertain until the refurbishment process begins. Although we believe that approximately $24.0 million per horizontal equivalent frac fleet is a reasonable estimate, the actual capital cost to redeploy the remainder of our stacked HHP may exceed our current estimates. Additionally, we currently expect a portion of our capital expenditure program for 2018 to consist of the purchase of advanced auxiliary well-site equipment and additional units within our other core service lines.

We expect to fund a portion of our 2018 capital expenditure program with borrowings under our Amended Credit Facility. The amount of indebtedness we have outstanding could limit our ability to finance future growth and could adversely affect our operations and financial condition.

Our primary sources of liquidity have historically included cash flows from operations, proceeds from public offerings of common stock and borrowings under debt facilities. Future cash flows are subject to a number of variables, many of which are beyond our control, and are highly dependent on the drilling, completion and production activity by our customers, which in turn is highly dependent on oil and gas prices. See Part I, Item 2 “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. Please also read “-Financial Condition and Cash Flows” below for information about net cash provided by or used in our operating, investing and financing activities.

Based on our existing operating performance, we currently believe that our cash flows from operations, cash on hand and borrowings under our Amended 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 (in thousands):



	Successor			Predecessor
	Years Ended December 31,
	2017			2016			2015
Cash flow provided by (used in):
Operating activities	$	94		$	(107,372	)	$	103,005
Investing activities	(275,686		)	(26,927		)	(825,156		)
Financing activities	210,339			174,264			734,126
Effect of exchange rate on cash	(2,102		)	(1,282		)	3,908
Increase (decrease) in cash and cash equivalents	$	(67,355	)	$	38,683		$	15,883

Cash Provided by (Used in) Operating Activities

Net cash from 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 $106.5 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 and adjustments for non-cash items of $714.5 million, partially offset by

cash inflows of $101.3 million due to (i) 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, (ii) 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 (iii) positive changes in other operating assets and liabilities, excluding accounts receivable, inventory, accounts payable and accrued expenses.

Net cash from operating activities was $103.0 million for the year ended December 31, 2015. The cash inflow was primarily related to (i) cash inflows of $148.1 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, 2015 and (ii) cash collections from accounts acquired as part of the Nabors Merger. These cash inflows were partially offset by (i) a net loss of $872.5 million and adjustments for non-cash items of $857.7 million, (ii) cash used to satisfy obligations related to accounts payable and accrued liabilities assumed in the Nabors Merger and (iii) negative 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 $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 (i) $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 and (ii) $1.8 million in payments related to our non-core service lines. These amounts were offset by $32.8 million of proceeds from disposal of property plant and equipment.

Net cash used in investing activities was $825.2 million for the year ended December 31, 2015. The use of cash was primarily related to $663.3 million primarily for cash consideration for the C&P Business, and $166.3 million of capital expenditures primarily pertaining to maintenance of our existing equipment. These amounts were offset by $4.5 million of proceeds from the disposal of property plant and equipment.

Cash Flows Provided by Financing Activities

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 Amended 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, (ii) $23.0 million in proceeds from the DIP Facility partially offset by (i) $13.3 million in payments on the Predecessor's revolving credit facility and term debt, (ii) $5.6 million of payments 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.

Net cash provided by financing activities was $734.1 million for the year ended December 31, 2015. The cash provided was primarily from $1.3 billion in proceeds from the Predecessor's term debt and revolving credit facility to fund the cash consideration portion of the acquisition of the C&P Business, partially offset by (i) $540.0 million in payments on the Predecessor's term debt and revolving credit facility, (ii) $55.5 million of cash paid for financing costs related to the Predecessor's term debt and revolving credit facility, (iii) $3.9 million in payments related to capital lease obligations, (iv) $2.6 million of employee tax withholding on restricted stock vesting, (v) $2.4 million of payments for excess tax expense from share-based compensation and (vi) $1.5 million of cash paid for registration costs associated with the issuance of common stock.

Description of our Indebtedness

Description of our Amended Credit Facility

The Successor and certain of its subsidiaries (the “Borrowers”) entered into the New Credit Facility on the Plan Effective Date, and on May 4, 2017, entered into the Amended Credit Facility.

The Amended Credit Facility allows the Borrowers to incur revolving loans in an aggregate amount up to the lesser of (a) $200.0 million or (b) a borrowing base, which borrowing base is based upon the value of the Borrowers’ accounts receivable and inventory, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion.

The Amended Credit Facility also provides for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Amended Credit Facility is May 4, 2022.

If at any time the amount of loans and other extensions of credit outstanding under the Amended Credit Facility exceeds the borrowing base, the Borrowers may be required, among other things, to prepay outstanding loans immediately.

The Borrowers’ obligations under the Amended 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 Amended Credit Facility.

At the Borrowers’ election, interest on borrowings under the Amended Credit Facility will be determined by reference to either LIBOR plus an applicable margin of 2.0% or an “alternate base rate” plus an applicable margin of 1.0%. These margins are subject to a monthly step-up of 0.25% in the event that average excess availability under the Amended Credit Facility is less than 37.5% of the total commitment, and a monthly step-down of 0.25% in the event that average excess availability under the Amended Credit Facility is equal to or greater than 62.5% of the total commitment. 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. The Borrowers will also be required to pay a fee on the unused portion of the Amended Credit Facility equal to (i) 0.75% in the event that utilization is less than 25.0% of the total commitment, (ii) 0.50% in the event that utilization is equal to or greater than 25% of the total commitment but less than 50% of the total commitment and (iii) 0.375% in the event that utilization is equal to or greater than 50% of the total commitment.

The Amended Credit Facility contains covenants that limit the Borrowers’ and their subsidiaries’ ability to incur additional indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, make capital expenditures or engage in certain asset dispositions including a sale of all or substantially all of the Company’s assets.

The Amended Credit Facility also contains a financial covenant which requires the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 if, as of any month-end, liquidity is less than $40.0 million.

The fixed charge coverage ratio is generally defined in the Amended 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.

Debtor-in-Possession $100 Million Term Loan Facility

Prior to the execution of the New Credit Facility, certain DIP Lenders agreed to fund a $100 million DIP Facility.

The borrowers under the DIP Facility were the Company and CJ Holding Co. All obligations under the DIP Facility were guaranteed by the Company’s subsidiaries that were debtors in the Bankruptcy cases. Borrowings under the DIP Credit Agreement were generally secured by superpriority priming liens on substantially all of the assets of the borrowers and guarantors.

The DIP Facility was scheduled to mature on March 31, 2017.

Amounts outstanding under the DIP Facility bore interest based on, at the option of the borrower, the London Interbank Offered Rate (“LIBOR”) or an alternative base rate, plus an applicable margin equal to 9.0% in the case of LIBOR loans and 8.0% in the case of base rate loans. The alternative base rate was equal to the highest of (i) the published ‘prime rate’, (ii) the Federal Funds Effective Rate (as defined in the DIP Credit Agreement) plus 0.5% and (iii) LIBOR plus 1.0%.

The DIP Facility also required that the Company pay various fees to the DIP Lenders, including a commitment fee equal to 5.0% of the unused commitments thereunder.

In accordance with the Restructuring Plan, on the Plan Effective Date, we repaid all amounts outstanding under the DIP Facility with the proceeds from the Rights Offering and the DIP Facility was canceled and discharged.

Description of the Original Credit Agreement

On March 24, 2015, we entered into a credit agreement (the “Original Credit Agreement”), among C&J, CJ Lux Holdings S.à r.l. (“Luxco”), CJ Holding Co, Bank of America, N.A., as Administrative Agent (in such capacity, the “Administrative Agent”), Swing Line Lender and an L/C Issuer, and the other lenders party thereto. The Original Credit Agreement provided for senior secured credit facilities (collectively, the “Credit Facilities”) in an aggregate principal amount of $1.66 billion, consisting of (a) a $600.0 million revolving credit facility (“Revolving Credit Facility” or “Revolver”) and (b) a Term Loan B Facility in the aggregate principal amount of $1.06 billion, comprised of two tranches: (i) a tranche consisting of $575.0 million in original aggregate principal amount of term loans maturing on March 24, 2020 (the “Five-Year Term Loans”) and (ii) a tranche consisting of a $485.0 million in original aggregate principal amount of term loans maturing on March 24, 2022 (the “Seven-Year Term Loans”).

The borrowers under the Revolving Credit Facility were C&J, Luxco and CJ Holding Co. The borrower under the Term Loan B Facility was CJ Holding Co. All obligations under the Original Credit Agreement were guaranteed by CJ Holding Co.'s wholly-owned domestic subsidiaries, other than immaterial subsidiaries and certain other customary exceptions.

Borrowings under the Revolving Credit Facility were scheduled to mature on March 24, 2020 (except that if any Five-Year Term Loans had not been repaid prior to September 24, 2019, the Revolving Credit Facility was scheduled to mature on September 24, 2019).

Borrowings under the Revolving Credit Facility were non-amortizing. The Term Loan B Facility required the borrower thereunder to make quarterly amortization payments in an amount equal to 1.0% per annum, with the remaining balance payable on the applicable maturity date.

Amounts outstanding under the Revolving Credit Facility bore interest based on, at the option of the borrower, the LIBOR or an alternative base rate, plus an applicable margin based on the ratio of consolidated total indebtedness of C&J and its subsidiaries to consolidated EBITDA of C&J and its subsidiaries for the most recent four fiscal quarter period for which financial statements are available (the “Total Leverage Ratio”). The Revolving Credit Facility also required that the borrowers pay a commitment fee equal to a percentage of unused commitments which varied based on the Total Leverage Ratio.

Five-Year Term Loans outstanding under the Term Loan B Facility bore interest based on, at the option of the borrower, LIBOR (which, in the case of the Term Loan B Facility, was deemed to be no less than 1.0% per annum), plus a margin of 5.5%, or an alternative base rate, plus a margin of 4.5%. Seven-Year Term Loans outstanding under the Term Loan B Facility bore interest based on, at the option of the borrower, LIBOR (which, in the case of the Term Loan B Facility, will be deemed to be no less than 1.0% per annum), plus a margin of 6.25%, or an alternative base rate, plus a margin of 5.25%.

The alternative base rate was equal to the highest of (i) the Administrative Agent’s prime rate, (ii) the Federal Funds Effective Rate plus 0.5% and (iii) LIBOR plus 1.0%.

On the Plan Effective Date, except as otherwise specifically provided for in the Restructuring Plan, the obligations of the Debtors under the Original Credit Agreement, any guarantees, and any other certificate, share, note, bond, indenture, purchase right, option, warrant, or other instrument or document directly or indirectly evidencing or creating any indebtedness or obligation of or ownership interest in any of the Debtors giving rise to any claim or equity interest (except as provided under the Restructuring Plan), were canceled as to the Debtors and their affiliates, and the reorganized Company and its affiliates ceased to have any obligations thereunder.

Contractual Obligations

The following table summarizes our contractual cash obligations as of December 31, 2017 (in thousands):



Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Service equipment and components	$	18,371	$	18,371	$	—	$	—	$	—
Operating leases	29,040		9,076		10,456		7,021		2,487
Amended Credit Facility ⁽¹⁾	7,670		1,738		3,476		2,456		—
Administrative contracts	1,369		1,099		270		—		—
Total	$	56,450	$	30,284	$	14,202	$	9,477	$	2,487

⁽¹⁾ Represents unused commitment fees on unused portion of the Amended Credit Facility and outstanding letters of credit. As of December 31, 2017, there were no amounts outstanding under the Amended 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, 2017.

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.

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.

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.

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 at the service line level, which consists of the well support services, fracturing, cased-hole wireline and pumping services, well construction & intervention, and data acquisition and control instruments provider service lines as well as the research and technology ("R&T") service lines 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. Our Other Services Segment which consisted of our smaller, non-core service lines such as our specialty chemical business, equipment manufacturing and repair business and international coiled tubing operations in the Middle East was divested in 2016. In line with the discontinuance of these small, ancillary service lines and divisions, subsequent to the year ended December 31, 2016, we are now disclosing two reportable segments. Consistent with our new structure, goodwill may be allocated across two reporting units: Completions Services 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.

Before employing detailed 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, detailed testing methodologies are then applied. Otherwise, we conclude that no impairment has occurred. Detailed impairment testing, or Step 1 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. If the carrying value of the reporting unit exceeds its fair value, a second step is required to measure possible goodwill impairment loss. The second step, or Step 2 testing, includes hypothetically valuing the tangible and intangible assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Then, the implied fair value of the reporting unit’s goodwill is compared to the carrying value of that goodwill. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess, not to exceed the carrying value.

Our Step 1 impairment analysis 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. Critical assumptions include projected revenue growth, fleet count, utilization, gross profit rates, 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. 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 it is reviewed for impairment when a triggering event indicates the trade name, on a stand-alone basis, may have a net book value in excess of consolidated C&J recoverable value using the same recoverability testing noted above.

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 12 - Mergers and 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. All revenue is recognized when persuasive evidence of an arrangement exists, the service is complete or the equipment has been delivered to the customer, the amount is fixed or determinable and collectibility is reasonably assured, as follows:

Completion Services Segment

Fracturing Services Revenue. Through our fracturing service line, we provide fracturing services pursuant to contractual arrangements, such as term contracts and pricing agreements or on a spot market basis. Under either scenario, revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or more fracturing stages. Once a job has been completed, a field ticket is written that includes charges for the services performed and the consumables (such as fluids and proppants) used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables.

Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate for a specified number of hours of service.

Pursuant to pricing agreements and other contractual arrangements that we may enter into from time to time, such as those associated with an award from a bid process, customers typically commit to targeted utilization levels based on a specified number of hours of service at agreed-upon pricing, but without termination penalties or obligations to pay for services not used by the customer. In addition, the agreed-upon pricing is typically subject to periodic review, as specifically defined in the agreement, and may be adjusted upon the agreement of both parties.

Cased-hole Wireline & Pumping Services Revenue. Through our Cased-hole Wireline and Pumping Services business, we provide cased-hole wireline, pumping, wireline logging, perforating, well site make-up and pressure testing and other complementary services, on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. We typically charge the customer for these services on a per job basis at agreed-upon spot market rates. Revenue is recognized based on a field ticket issued upon the completion of the job.

Well Construction and Intervention Services Revenue. Through our well construction and intervention services business, we provide cementing, coiled tubing and directional drilling services.

With respect to our cementing services, we provide these services on a spot market or project basis. Jobs for these services are typically short-term in nature and are generally completed in a few hours. We typically charge the customer for these services on a per job basis at agreed-upon spot market rates or agreed-upon job pricing for a particular project. Revenue is recognized and customers are invoiced upon the completion of each job. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the consumables (such as blended bulk cement and chemical additives) used during the course of service.

With respect to our coiled tubing services, we provide a range of coiled tubing services primarily used for frac plug drill-out during completion operations and for well workover and maintenance, primarily on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. Revenue is recognized upon completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the services performed and the consumables (such as stimulation fluids, nitrogen and coiled tubing materials) used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables. We typically charge the customer for the services performed and resources provided on an hourly basis at agreed-upon spot market rates or pursuant to contractual arrangements such as term contracts and pricing agreements.

With respect to our directional drilling services, we provide these services on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few days to multiple weeks. We typically charge the customer for these services on a per day basis at agreed-upon spot market rates depending on the level of services required and the complexity of the job. Revenue is recognized and customers are invoiced upon the completion of each job. Once a job has been completed, a field ticket is written that includes charges for the service performed.

Revenue from Materials Consumed While Performing Certain Completion Services. We generate revenue from consumables used during the course of providing services.

With respect to our fracturing services, we generate revenue from the fluids, proppants and other materials that are consumed while performing a job. For services performed on a spot market basis, the required consumables are typically provided by us and the customer is billed for those consumables at cost plus an agreed-upon markup. For services performed on a contractual basis, when the consumables are provided by us, the customer typically is billed for those consumables at a negotiated contractual rate. When consumables are supplied by the customer, we typically charge handling fees based on the amount of consumables used.

Other Completion Services Revenue. We generate revenue from our R&T department, which 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. Revenue is recognized upon the completion, delivery and customer acceptance of each order of parts and components.

Well Support Services Segment

Rig Services Revenue. Through our rig service line, we provide workover and well servicing rigs that are primarily used for routine repair and maintenance of oil and gas wells, re-drilling operations and plugging and abandonment operations. These services are provided on an hourly basis at agreed upon spot market rates. Revenue is recognized and a field ticket is generated upon the earliest of the completion of a job or at the end of each day. A rig services job can last anywhere from a few hours to multiple days depending on the type of work being performed. The field ticket includes the base hourly rate charge and, if applicable, charges for additional personnel or equipment not contemplated in the base hourly rate. The field ticket may also include charges for the mobilization and set-up of equipment,

Fluids Management Services Revenue. Through our fluids management service line, we primarily provide storage, transportation and disposal services for fluids used in the drilling, completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour or per load basis, or on the basis of quantities sold or disposed. Revenue is recognized upon the completion of each job or load, or delivered product, based on a completed field ticket.

Other Special Well Site Services Revenue. Through our other special well site service line, we primarily provide fishing, contract labor, and tool rental services for completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour or on the basis of rental days per month. Revenue is recognized based on a field ticket issued upon the completion of each job or on a monthly billing for rental services provided.

With respect to our artificial lift applications, we generate revenue primarily from the sale of manufactured equipment and products. Revenue is recognized upon the completion, delivery and customer acceptance of each order.

Other Services Segment

Revenue within our Other Services Segment was generated from certain of our smaller, non-core service lines that were divested in 2016 and 2017, such as our specialty chemical business, equipment manufacturing and repair business and international coiled tubing operations in the Middle East. In line with the discontinuance of these small, ancillary service lines and divisions, subsequent to the year ended December 31, 2016, we are now disclosing two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period.

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. At December 31, 2017 and 2016, the allowance for doubtful accounts totaled $4.3 million and $3.0 million, respectively. Bad debt expense of $4.4 million, $1.7 million and $8.1 million was included in direct costs on the consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015, respectively.

Share-Based Compensation. Our share-based compensation consists of restricted shares and nonqualified share options. We recognize share-based compensation expense on a straight-line basis over the requisite service period of the award. We value restricted share grants based on the closing price of our common stock on the grant date. We value option grants based on the grant date fair value using the Black-Scholes option-pricing model, and we value equity 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.

The Black-Scholes option-pricing model requires inputs such as the expected term of the grant, expected volatility and risk-free interest rate. Further, the forfeiture rate also affects the amount of aggregate compensation that we are required to record as an expense. We will continue to use judgment in evaluating the expected term, volatility and forfeiture rate related to our share-based compensation on a prospective basis and will incorporate these factors into our option-pricing model. Each of these inputs is subjective and generally requires significant management judgment. If, in the future, we determine that another method for calculating the fair value of our stock options is more reasonable, or if another method for calculating these input assumptions is prescribed by authoritative guidance, and, therefore, should be used to estimate expected volatility or expected term, the fair value calculated for our employee stock options could change significantly. Higher volatility and longer expected terms generally result in an increase to share-based compensation expense determined at the date of grant.

Income Taxes. We are subject to income and other similar taxes in all areas in which they 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 prior years that will expire in the years 2021 through 2037. 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, the Company 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 believes we experienced an ownership change for purposes of Section 382 of the Code because of its Restructuring Plan and in addition experienced a subsequent ownership change on or about June 30, 2017. Consequently, our pre-change NOLs are subject to an annual limitation (See Note 2 - 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, 2017, we recorded an income tax benefit of $6.5 million related to a decrease in the estimate of the reserve for unrecognized tax benefits relating to uncertain tax positions. The decrease resulted from the effect of changes in the application of relevant withholding tax provisions under applicable local country treaties related to certain our foreign subsidiaries. As of December 31, 2017, we have no uncertain tax positions.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued a comprehensive new revenue recognition standard, Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09") that will supersede existing revenue recognition guidance under U.S. GAAP. In August 2015, the FASB issued an accounting standards update for a one-year deferral of the revenue recognition standard's effective date for all entities, which changed the effectiveness to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statement line items. We adopted this new accounting standard on January 1, 2018 and upon adoption, we incorporated the modified retrospective approach as our transition method. The approach included performing a detailed review of key contracts representative of our different businesses and comparing historical accounting policies and practices to the new standard. Based on this assessment, the Company has concluded the adoption of this new account standard will not have a material impact on our consolidated financial statements.

In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory ("ASU 2015-11"), which changes the measurement principle for inventory from the lower of cost or market to lower of cost and net realizable value. ASU 2015-11 is part of the FASB’s simplification initiative and applies to entities that measure inventory using a method other than last-in, first-out ("LIFO") or the retail inventory method. We adopted ASU 2015-11 on January 1, 2017 prospectively and the adoption had no effect on our consolidated financial statements.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes ("ASU 2015-17”). ASU 2015-17 amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as non-current on the balance sheet. We adopted ASU 2015-17 on January 1, 2017 prospectively and no prior periods have been restated to conform to the new presentation. The adoption had no effect on our results of operations or financial position.

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 are currently evaluating the impact of adopting this new accounting standard on our consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting ("ASU 2016-09"), to simplify certain provisions in stock compensation accounting, including the simplification of accounting for a stock payment's tax consequences. The ASU amends the guidance for classifying awards as either equity or liabilities, allows companies to estimate the number of stock awards they expect to vest, and revises the tax withholding requirements for stock awards. The amendments in ASU No. 2016-09 are effective for public companies for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, and early application is permitted. We adopted ASU 2016-09 on January 1, 2017 prospectively and the adoption had no effect on our results of operations or financial position.

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 consolidated financial statements.

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. We anticipate a cumulative effect adjustment to reduce retained earnings by approximately $13.2 million will occur as a result of our adoption of ASU 2016-16.

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 a drop in value. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019 and early adoption is permitted. We do not expect the adoption of this new accounting standard to have a significant impact 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, 2017, 2016 and 2015. 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.

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 Amended Credit Facility. As of December 31, 2017, we had no debt outstanding under our Amended Credit Facility. The impact of a 1.0% increase in interest rates under the terms of the Amended Credit Facility would have no impact on interest expense for the 2017 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.

Item 8. Financial Statements and Supplementary Data

Index to

Consolidated Financial Statements





Management's Report on Internal Control Over Financial Reporting	66
Reports of Independent Registered Public Accounting Firms	67
Consolidated Balance Sheets as of December 31, 2017 (Successor) and 2016 (Predecessor)	69
Consolidated Statements of Operations for the Year Ended December 31, 2017 (Successor), on January 1, 2017 (Predecessor) and for the Years Ended December 31, 2016 (Predecessor) and 2015 (Predecessor)	70
Consolidated Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2017 (Successor), on January 1, 2017 (Predecessor) and for the Years Ended December 31, 2016 (Predecessor) and 2015 (Predecessor)	71
Consolidated Statements of Changes in Stockholders’ Equity for the Year Ended December 31, 2017 (Successor), on January 1, 2017 (Predecessor) and for the Years Ended December 31, 2016 (Predecessor) and 2015 (Predecessor)	72
Consolidated Statements of Cash Flows for the Year Ended December 31, 2017 (Successor), on January 1, 2017 (Predecessor) and for the Years Ended December 31, 2016 (Predecessor) and 2015 (Predecessor)	73
Notes to Consolidated Financial Statements	74

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, 2017. 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, 2017.

Management’s assessment of the Company’s internal control over financial reporting as of December 31, 2017 excluded the internal control over financial reporting of O-Tex Holdings, Inc., and its operating subsidiaries ("O-Tex"), which was acquired by the Company on November 30, 2017. O-Tex represented approximately 1% of consolidated revenues and 20% of consolidated total assets as of December 31, 2017.

The Company's internal control over financial reporting as of December 31, 2017 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/ Mark C. Cashiola	/s/ Michael S. Galvan
Donald J. Gawick President, Chief Executive Officer and Director (Principal Executive Officer)	Mark C. Cashiola Chief Financial Officer (Principal Financial Officer)	Michael S. Galvan Chief Accounting Officer (Principal Accounting Officer)

March 1, 2018

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, 2017 (Successor) and 2016 (Predecessor), the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for the year ended December 31, 2017 (Successor), and for the years ended 2016 and 2015 (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, 2017 (Successor) and 2016 (Predecessor), and the results of its operations and its cash flows for the year ended December 31, 2017 (Successor) and for the years ended 2016 and 2015 (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, 2017, 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 March 1, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis of Accounting

As discussed in Note 1 to the consolidated financial statements, on December 15, 2016, the United States Bankruptcy Court in the Southern District of Texas entered an order confirming the Company’s plan for reorganization under Chapter 11 of the Bankruptcy Code, which became effective on January 6, 2017. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with Accounting Standards Codification 852, Reorganizations, for the Successor as a new reporting entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods as described in Note 1.

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.

/s/ KPMG LLP

We have served as the Company's auditor since 2014

Houston, Texas

March 1, 2018

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, 2017, 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, 2017, 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, 2017 (Successor) and 2016 (Predecessor), the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for the year ended December 31, 2017 (Successor), and for the years ended 2016 and 2015 (Predecessor), and related notes (collectively, the consolidated financial statements), and our report dated March 1, 2018 expressed an unqualified opinion on those consolidated financial statements.

The Company acquired O-Tex Holdings, Inc. (O-Tex) during 2017, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2017, O-Tex’s internal control over financial reporting associated with approximately 20% of consolidated assets and 1% of consolidated revenues included in the consolidated financial statements of the Company as of and for the year ended December 31, 2017. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of O-Tex.

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

March 1, 2018

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share data)



	Successor			Predecessor
	December 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	113,887		$	64,583
Accounts receivable, net of allowance of $4,269 at December 31, 2017 and $2,951 at December 31, 2016	367,906			137,084
Inventories, net	77,793			54,471
Prepaid and other current assets	33,011			37,611
Deferred tax assets	—			6,020
Total current assets	592,597			299,769
Property, plant and equipment, net of accumulated depreciation of $133,755 at December 31, 2017 and $683,189 at December 31, 2016	703,029			950,811
Other assets:
Goodwill	147,515			—
Intangible assets, net	123,837			76,057
Deferred financing costs, net of accumulated amortization of $608, as of December 31, 2017	3,379			—
Other noncurrent assets	38,500			35,045
Total assets	$	1,608,857		$	1,361,682
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	138,624		$	74,382
Payroll and related costs	52,812			17,991
Accrued expenses	66,547			60,363
DIP Facility	—			25,000
Other current liabilities	867			2,980
Total current liabilities	258,850			180,716
Deferred tax liabilities	3,917			15,613
Other long-term liabilities	24,668			18,577
Total liabilities not subject to compromise	287,435			214,906
Liabilities subject to compromise	—			1,445,346
Commitments and contingencies
Stockholders’ equity
Predecessor common shares, par value of $0.01, 750,000,000 shares authorized, 119,529,942 issued and outstanding at December 31, 2016	—			1,195
Predecessor additional paid-in capital	—			1,009,426
Successor common stock, par value of $0.01, 1,000,000,000 shares authorized, 68,546,820 issued and outstanding at December 31, 2017	686			—
Successor additional paid-in capital	1,298,859			—
Accumulated other comprehensive loss	(580		)	(2,600		)
Retained earnings (deficit)	22,457			(1,306,591		)
Total stockholders’ equity (deficit)	1,321,422			(298,570		)
Total liabilities and stockholders’ equity (deficit)	$	1,608,857		$	1,361,682

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands, except per share data)



	Successor			Predecessor
	Year Ended December 31,			On January 1,			Years Ended December31,
	2017			2017			2016			2015
Revenue	$	1,638,739		$	—		$	971,142		$	1,748,889
Costs and expenses:
Direct costs	1,288,092			—			947,255			1,523,194
Selling, general and administrative expenses	250,871			—			229,267			239,697
Research and development	6,368			—			7,718			16,704
Depreciation and amortization	140,650			—			217,440			276,353
Impairment expense	—			—			436,395			791,807
(Gain) loss on disposal of assets	(31,463		)	—			3,075			(544		)
Operating income (loss)	(15,779		)	—			(870,008		)	(1,098,322		)
Other income (expense):
Interest expense, net	(1,527		)	—			(157,465		)	(82,086		)
Other income (expense), net	3			—			9,504			8,773
Total other income (expense)	(1,524		)	—			(147,961		)	(73,313		)
Losses before reorganization items and income taxes	(17,303		)	—			(1,017,969		)	(1,171,635		)
Reorganization items	—			(293,969		)	55,330			—
Income tax benefit	(39,760		)	(4,613		)	(129,010		)	(299,093		)
Net income (loss)	$	22,457		$	298,582		$	(944,289	)	$	(872,542	)
Net income (loss) per common share:
Basic	$	0.37		$	2.52		$	(7.98	)	$	(8.48	)
Diluted	$	0.37		$	2.52		$	(7.98	)	$	(8.48	)
Weighted average common shares outstanding:
Basic	61,208			118,633			118,305			102,853
Diluted	61,460			118,633			118,305			102,853

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)



	Successor			Predecessor
	Year Ended December 31,			On January 1,		Years Ended December 31,
	2017			2017		2016			2015
Net income (loss)	$	22,457		$	298,582	$	(944,289	)	$	(872,542	)

Other comprehensive income (loss):
Foreign currency translation gain (loss), net of income tax (expense) benefit of ($777), ($31) and $1,369 as of December 31, 2017, 2016 and 2015 respectively	(580		)	—		1,425			(3,980		)
Comprehensive income (loss)	$	21,877		$	298,582	$	(942,864	)	$	(876,522	)

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(Amounts in thousands)



	Common Stock					Additional Paid-in Capital			Other Comprehensive Loss			Retained Earnings (Deficit)			Total
	Number of Shares		Amount, at $0.01 par value			Additional Paid-in Capital			Other Comprehensive Loss			Retained Earnings (Deficit)			Total
Balance, December 31, 2014 (Predecessor)	55,333		$	553		$	271,104		$	(45	)	$	510,240		$	781,852
Issuance of common shares, net of issuance costs	62,542		625			709,642			—			—			$	710,267
Issuance of restricted shares, net of forfeitures	2,613		26			3,006			—			—			3,032
Employee tax withholding on restricted shares vesting	(222	)	(2		)	(2,619		)	—			—			(2,621		)
Issuance of common shares for stock options exercised	154		2			451			—			—			453
Tax effect of share-based compensation	—		—			(2,367		)	—			—			(2,367		)
Share-based compensation	—		—			18,549			—			—			18,549
Net income	—		—			—			—			(872,542		)	(872,542		)
Foreign currency translation loss, net of tax	—		—			—			(3,980		)	—			(3,980		)
Balance, December 31, 2015 (Predecessor)	120,420		1,204			997,766			(4,025		)	(362,302		)	632,643
Forfeitures of restricted shares	(576	)	(6		)	6			—			—			—
Employee tax withholding on restricted shares vesting	(314	)	(3		)	(494		)	—			—			(497		)
Tax effect of share-based compensation	—		—			(5,592		)	—			—			(5,592		)
Share-based compensation	—		—			17,740			—			—			17,740
Net loss	—		—			—			—			(944,289		)	(944,289		)
Foreign currency translation gain, net of tax	—		—			—			1,425			—			1,425
Balance, December 31, 2016 (Predecessor)	119,530		1,195			1,009,426			(2,600		)	(1,306,591		)	(298,570		)
Cancellation of Predecessor equity	(119,530	)	(1,195		)	(1,009,426		)	2,600			1,306,591			298,570


Issuance of New Equity and New Warrants	40,000		400			725,464			—			—			725,864
Rights Offering	15,464		155			199,845			—			—			200,000
Balance January 1, 2017 (Successor)	55,464		555			925,309			—			—			925,864
Public offering of common stock, net of offering costs	7,050		71			215,849			—			—			215,920
Issuance of stock for business acquisition	4,420		44			138,122			—			—			138,166
Issuance of restricted stock, net of forfeitures	1,718		17			(17		)	—			—			—
Exercise of warrants	2		—			—			—			—			—
Employee tax withholding on restricted stock vesting	(107	)	(1		)	(3,841		)	—			—			(3,842		)
Share-based compensation	—		—			23,437			—			—			23,437
Net income	—		—			—			—			22,457			22,457
Foreign currency translation loss, net of tax	—		—			—			(580		)	—			(580		)
Balance December, 31, 2017 (Successor)	68,547		$	686		$	1,298,859		$	(580	)	$	22,457		$	1,321,422

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)



	Successor			Predecessor
	Year Ended December 31,			On January 1,			Years Ended December 31,
	2017			2017			2016			2015
Cash flows from operating activities:
Net income (loss)	$	22,457		$	298,582		$	(944,289	)	$	(872,542	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	140,650			—			217,440			276,353
Impairment expense	—			—			436,395			791,807
Inventory write-down	—			—			35,350			31,109
Contingent consideration adjustment	—			—			(4,700		)	(11,147		)
Deferred income taxes	(31,244		)	(4,613		)	(129,533		)	(273,144		)
Provision for doubtful accounts	4,444			—			1,735			8,071
Equity (earnings) loss from unconsolidated affiliate	83			—			5,663			(500		)
(Gain) loss on disposal of assets	(31,463		)	—			3,075			(544		)
Share-based compensation expense	23,437			—			17,740			18,549
Amortization of deferred financing costs	608			—			48,310			10,926
Accretion of original issue discount	—			—			52,414			6,187
Reorganization items, net	—			(315,626		)	30,611			—
Changes in operating assets and liabilities:
Accounts receivable	(203,101		)	—			137,075			278,150
Inventories	(26,072		)	—			4,244			21,123
Prepaid expenses and other current assets	16,013			—			24,447			(26,821		)
Accounts payable	41,801			—			(75,016		)	(168,607		)
Payroll and related costs and accrued expenses	38,104			(1,436		)	35,028			17,400
Liabilities subject to compromise	—			(33,000		)	—			—
Income taxes receivable (payable)	1,714						3,604			(108		)
Other	2,663			—			(6,965		)	(3,257		)
Net cash provided by (used in) operating activities	94			(56,093		)	(107,372		)	103,005
Cash flows from investing activities:
Purchases of and deposits on property, plant and equipment	(210,186		)	—			(57,909		)	(166,321		)
Proceeds from disposal of property, plant and equipment and non-core service lines	68,250			—			32,809			4,468
Payments made for business acquisitions	(133,750		)	—			—			(663,303		)
Other payments related to non-core service lines	—						(1,827		)	—
Net cash used in investing activities	(275,686		)	—			(26,927		)	(825,156		)
Cash flows from financing activities:
Proceeds from revolving debt and term loans	—			—			174,000			1,339,400
Payments on revolving debt and term loans	—			—			(13,250		)	(539,950		)
Proceeds from DIP Facility	—			—			23,000			—
Payments on DIP Facility	—			(25,000		)	—			—
Payments of capital lease obligations	—			—			(2,388		)	(3,874		)
Financing costs	(1,739		)	(2,248		)	(1,009		)	(55,450		)
Proceeds from issuance of common stock, net of offering costs	215,920			200,000			—			453
Registration costs associated with issuance of common stock	—			—			—			(1,465		)
Employee tax withholding on restricted stock vesting	(3,842		)	—			(497		)	(2,621		)
Excess tax benefit (expense) from share-based compensation	—			—			(5,592		)	(2,367		)
Net cash provided by financing activities	210,339			172,752			174,264			734,126

Effect of exchange rate on cash	(2,102		)	—			(1,282		)	3,908
Net increase (decrease) in cash and cash equivalents	(67,355		)	116,659			38,683			15,883
Cash and cash equivalents, beginning of year	181,242			64,583			25,900			10,017
Cash and cash equivalents, end of year	$	113,887		$	181,242		$	64,583		$	25,900

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Organization, Nature of Business and Summary of Significant Accounting Policies

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” or the “Company”), is a leading provider of well construction, well completion, well support and other complementary oilfield services to oil and gas exploration and production ("E&P") companies throughout the continental United States. The Company offers an integrated suite of services throughout the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, directional drilling, rig services, fluids management, artificial lift, and other completion and specialty well site support services. The Company is headquartered in Houston, Texas, and operates across all active onshore basins in the continental United States.

C&J’s business was founded in Texas in 1997 as a partnership and converted to a Delaware corporation (“Old C&J”) in connection with an initial public offering which was completed in 2011 with a listing on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” 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 nearly tripled the Company’s size, significantly expanding the Company’s Completion Services business and adding the Well Support Services division to the Company’s service offerings. 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,” or the “Company”), and shares of common stock of Old C&J were converted into common shares of the Predecessor on a 1-for-1 basis.

Due to the severe industry downturn, on July 20, 2016 (the "Petition Date"), 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 (the "Bankruptcy Court"), with ancillary recognition proceedings filed in Canada and Bermuda (collectively, the "Chapter 11 Proceeding").

Upon emergence from the Chapter 11 Proceeding, the Company adopted Fresh Start accounting in accordance with the provisions set forth in Accounting Standards Codification (“ASC”) 852 - Reorganizations. For more information regarding the adoption of Fresh Start accounting, see Note 3 - Fresh Start Accounting.

Basis of Presentation and Principles of Consolidation

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and include all of the accounts of C&J and its consolidated subsidiaries. All significant inter-company transactions and account balances have been eliminated upon consolidation.

As discussed above the Company adopted Fresh Start accounting in accordance with the provisions set forth in ASC 852 with respect to the accounting and financial statement disclosures. Accordingly, the Company's consolidated financial statements and notes prior to January 1, 2017, are not comparable to the consolidated financial statements as of January 1, 2017 and periods subsequent to January 1, 2017.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company’s results for the year ended 2015 include results from the C&P Business from the closing of the Nabors Merger on March 24, 2015 through December 31, 2015. Results for periods prior to March 24, 2015 reflect the financial and operating results of Old C&J, and do not include the financial and operating results of the C&P Business.

During the fourth quarter of 2015, the Company recorded out-of-period adjustments to correct the overstatement from the over-accrual of direct costs related to periods from 2008 through December 31, 2014, resulting in a $9.8 million increase to net income. In evaluating whether these errors, individually and in the aggregate, and the corrections of the errors had a material impact to the periods such errors and corrections related to, the Company evaluated both the quantitative and qualitative impact to its consolidated financial statements for such periods. In assessing the quantitative impact, the Company considered the errors in each impacted period relative to the amount of reported direct costs, net income or loss, and current and total liabilities. The Company considered a number of qualitative factors, including, among others, that the errors and the correction of the errors (i) did not change a net loss into net income or vice versa, (ii) did not have an impact on the Company's debt covenant compliance and (iii) did not result in a change in the Company's earnings trends when considering the overall competitive and economic environment within which it operated from 2008 through December 31, 2014. Based upon the Company's quantitative and qualitative evaluation, it determined that the errors and the correction of such errors did not have a material impact to prior periods, individually or in the aggregate, and were not material to the year ending December 31, 2015.

Summary of Significant Accounting Policies

Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Estimates are used in, but are not limited to, determining the following: allowance for doubtful accounts, valuation of long-lived assets and intangibles, goodwill, useful lives used in depreciation and amortization, inventory reserves, income taxes, share-based compensation and liabilities subject to compromise under the provisions of ASC 852 fresh start accounting ("Fresh Start"). The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, or as additional information is obtained and as the Company’s operating environment changes.

Cash and Cash Equivalents. For purposes of the consolidated statement of cash flows, cash is defined as cash on-hand, demand deposits, and short-term investments with initial maturities of three months or less. The Company maintains its cash and cash equivalents in various financial institutions, which at times may exceed federally insured amounts. Management believes that this risk is not significant. Cash balances related to the Company's captive insurance subsidiaries, which totaled $23.8 million and $16.1 million at December 31, 2017 and December 31, 2016, respectively, are included in cash and cash equivalents in the consolidated balance sheets, and the Company expects to use these cash balances to fund the operations of the captive insurance subsidiaries and to settle future anticipated claims.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are generally stated at the amount billed to customers. The Company provides 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. At December 31, 2017 and 2016, the allowance for doubtful accounts totaled $4.3 million and $3.0 million, respectively. Bad debt expense of $4.4 million, $1.7 million and $8.1 million was included in selling, general, and administrative expenses on the consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015, respectively.

Inventories. Inventories are carried at the lower of cost or net realizable value. Inventories for the Company consist of raw materials, work-in-process and finished goods, including equipment components, chemicals, proppants, supplies and materials for the Company's operations.

Consistent with FASB requirements under ASC 852, an entity adopting fresh-start accounting may generally set new accounting policies for the successor independent of those followed by the predecessor. The entity emerging from bankruptcy typically is not required to demonstrate preferability for its new accounting policies, as the successor entity represents a new entity for financial reporting purposes.

During January 2017, the Company implemented a new computer system that provides financial reporting, inventory management and fixed asset management capabilities (the "new ERP system") to enhance functionality and to support the Company's existing and future operations. The new ERP system utilizes the weighted average cost flow method for determining inventory cost ("Weighted Average"), which replaced the first-in, first-out basis ("FIFO") method utilized by the Predecessor's legacy system. The Weighted Average and FIFO methods are both allowable under U.S. GAAP. As of the Fresh

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Start Reporting Date, the Company began utilizing the Weighted Average method for determining inventory cost. Inventory cost for the prior periods presented are still reflective of the FIFO method.

Inventories consisted of the following (in thousands):



	Successor			Predecessor
	As of December 31,
	2017			2016
Raw materials	$	5,302		$	16,367
Work-in-process	1,329			5,022
Finished goods	74,552			38,091
Total inventory	81,183			59,480
Inventory reserve	(3,390		)	(5,009		)
Inventory, net	$	77,793		$	54,471

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, which range from three to 25 years. Depreciation expense was $136.5 million, $206.7 million, and $261.8 million for the years ended December 31, 2017, 2016 and 2015, respectively. Major classifications of property, plant and equipment and their respective useful lives were as follows (in thousands):



		Successor			Predecessor
	Estimated Useful Lives	As of December 31,
	Estimated Useful Lives	2017			2016
Land	Indefinite	$	38,385		$	46,000
Building and leasehold improvements	5-25 years	79,985			121,915
Office furniture, fixtures and equipment	3-5 years	34,672			29,435
Machinery and equipment	3-10 years	577,922			1,219,645
Transportation equipment	3-10 years	23,352			179,426
		754,316			1,596,421
Less: accumulated depreciation		(133,755		)	(683,189		)
		620,561			913,232
Construction in progress		82,468			37,579
Property, plant and equipment, net		$	703,029		$	950,811

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. The Company determined the lowest level of identifiable cash flows that are independent of other asset groups to be primarily at the service line level. The Company's assets groups consist of the well support services, fracturing, cased-hole wireline and pumping services, well construction and intervention, artificial lift applications, and data acquisition and control instruments provider service lines as well as the research and technology ("R&T") service lines. If the estimated undiscounted future net cash flows for a given asset group is less than the carrying amount of the related assets, an

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

The Company concluded that the sharp fall in commodity prices during the second half of 2014 constituted a triggering event that resulted in a significant slowdown in activity across the Company’s customer base, which in turn increased competition and put pressure on pricing for its services throughout 2015 and 2016. Although uncertainty as to the severity and extent of this downturn still exists, activity and pricing levels may decline again in future periods. As a result of the triggering event during the fourth quarter of 2014, PP&E recoverability testing was performed throughout 2015 and 2016 on the asset groups described above. During the fourth quarter of 2015, the recoverability testing for the hydraulic fracturing, coiled tubing, directional drilling, international coiled tubing, equipment manufacturing and repair services, specialty chemicals and the research and technology asset groups yielded an estimated undiscounted net cash flow that was less than the carrying amount of the related assets. The estimated fair value for each respective asset group was compared to its carrying value, and impairment expense of $393.1 million was recognized during the fourth quarter of 2015 and allocated across each respective asset group's major classification. The impairment charge was primarily related to underutilized pressure pumping and other equipment in the Completion Services and Other Services segments. For the 2016 year, the recoverability testing for the coiled tubing, directional drilling, cementing, artificial lift applications and international coiled tubing asset groups yielded an estimated undiscounted net cash flow that was less than the carrying amount of the related assets. The estimated fair value for each respective asset group was compared to its carrying value, and impairment expense of $61.1 million was recognized during 2016 and allocated across each respective asset group's major classification. The impairment charge was primarily related to underutilized equipment in the Completion Services and Other Services segments. The fair value of these assets was based on the projected present value of future cash flows that these assets are expected to generate. Should industry conditions not significantly improve or worsen, additional impairment charges may be required in future periods. No impairment charge was recorded for the year ended December 31, 2017.

On June 29, 2016, the Company sold a majority of the assets comprising their specialty chemicals supply business, including PP&E, for approximately $9.3 million of net cash.

PP&E impairment expense for the years ended December 31, 2016 and 2015 was recognized across each asset group as follows (in thousands). Certain asset groups reflected in the table below were part of the Company’s smaller, non-core service lines that were divested in 2016, such as the Company's specialty chemical business, equipment manufacturing and repair business and international coiled tubing operations in the Middle East.



	Predecessor
	Year Ended December 31,		Year Ended December 31,
	2016		2015
Fracturing	$	—	$	255,283
Well Construction & Intervention	49,877		101,171
International Coiled Tubing	4,663		6,931
Equipment Manufacturing and Repair Services	3,238		13,847
Specialty Chemicals	—		3,070
Artificial lift	2,784		—
Research and Technology	518		12,777
Total PP&E impairment expense	$	61,080	$	393,079

Goodwill, Indefinite-Lived Intangible Assets and Definite-Lived Intangible Assets. Goodwill may be allocated across two reporting units: Completions Services and Well Support Services. At the reporting unit level, the Company tests 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. During the third quarter of 2015, sustained low commodity price levels and the resulting impact on the Company’s results of operations, coupled with the sustained weakness in the Company’s share price were deemed triggering events that led to an interim period test for goodwill impairment. During the first quarter of 2016, commodity price levels remained depressed which materially and negatively impacted the Company's results of operations, and the further

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

declines in the Company's share price led to another interim period test for goodwill impairment. See Note 5 - Goodwill and Other Intangible Assets for further discussion on impairment testing results.

Before employing detailed impairment testing methodologies, the Company 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 the Company first utilizes a qualitative approach and determines that it is more likely than not that goodwill is impaired, detailed testing methodologies are then applied. Otherwise, the Company concludes that no impairment has occurred. Detailed impairment testing, or Step 1 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. If the carrying value of the reporting unit exceeds its fair value, a second step is required to measure possible goodwill impairment loss. The second step, or Step 2 testing, includes hypothetically valuing the tangible and intangible assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Then, the implied fair value of the reporting unit’s goodwill is compared to the carrying value of that goodwill. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess, not to exceed the carrying value.

The Company’s Step 1 impairment analysis 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. 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. The Company’s 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. 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, the Company performs a recoverability test on its 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 it is reviewed for impairment when a triggering event indicates the trade name, on a stand-alone basis, may have a net book value in excess of consolidated C&J recoverable value using the same recoverability testing noted above.

For further discussion of the application of this accounting policy regarding impairments, please see Note 5 - Goodwill and Other Intangible Assets.

Deferred Financing Costs. Costs incurred to obtain term debt financing are presented on the balance sheet as a direct deduction from the carrying amount of the term debt, consistent with debt discounts, and accreted over the term of the loan using the effective interest method. Costs incurred to obtain revolver based financing are capitalized and amortized over the term of the loan using the effective interest method. These costs are classified within interest expense on the consolidated statements of operations and were $0.6 million, $48.3 million and $10.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. Accumulated amortization of deferred financing costs was $0.6 million and $58.8 million at December 31, 2017 and 2016, respectively. As of December 31, 2016, and prior to emergence from the Chapter 11 Proceeding, deferred financing costs were fully amortized to zero.

Completion Services Segment

Fracturing Services Revenue. Through its fracturing service line, the Company provides fracturing services pursuant to contractual arrangements, such as term contracts and pricing agreements or on a spot market basis. Under either scenario, revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or more fracturing stages. Once a job has been completed, a field ticket is written that includes charges for the services performed and

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the consumables (such as fluids and proppants) used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables.

Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate for a specified number of hours of service.

Pursuant to pricing agreements and other contractual arrangements that the Company may enter into from time to time, such as those associated with an award from a bid process, customers typically commit to targeted utilization levels based on a specified number of hours of service at agreed-upon pricing, but without termination penalties or obligations to pay for services not used by the customer. In addition, the agreed-upon pricing is typically subject to periodic review, as specifically defined in the agreement, and may be adjusted upon the agreement of both parties.

Cased-hole Wireline & Pumping Services Revenue. Through its cased-hole wireline & pumping services business, the Company provides cased-hole wireline, pumping, wireline logging, perforating, well site make-up and pressure testing and other complementary services, on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. The Company typically charges the customer for these services on a per job basis at agreed-upon spot market rates. Revenue is recognized based on a field ticket issued upon the completion of the job.

Well Construction & Intervention Services Revenue. Through its well construction and intervention services business, the Company provides cementing, coiled tubing and directional drilling services.

With respect to its cementing services, the Company provides these services on a spot market or project basis. Jobs for these services are typically short-term in nature and are generally completed in a few hours. The Company typically charges the customer for these services on a per job basis at agreed-upon spot market rates or agreed-upon job pricing for a particular project. Revenue is recognized and customers are invoiced upon the completion of each job. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the consumables (such as blended bulk cement and chemical additives) used during the course of service.

With respect to its coiled tubing services, the Company provides a range of coiled tubing services primarily used for frac plug drill-out during completion operations and for well workover and maintenance, primarily on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. Revenue is recognized upon completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the services performed and the consumables (such as stimulation fluids, nitrogen and coiled tubing materials) used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables. The Company typically charges the customer for the services performed and resources provided on an hourly basis at agreed-upon spot market rates or pursuant to contractual arrangements such as term contracts and pricing agreements.

With respect to its directional drilling services, the Company provides these services on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few days to multiple weeks. The Company typically charges the customer for these services on a per day basis at agreed-upon spot market rates depending on the level of services required and the complexity of the job. Revenue is recognized and customers are invoiced upon the completion of each job. Once a job has been completed, a field ticket is written that includes charges for the service performed.

Revenue from Materials Consumed While Performing Certain Completion Services. The Company generates revenue from consumables used during the course of providing services.

With respect to fracturing services, the Company generates revenue from the fluids, proppants and other materials that are consumed while performing a job. For services performed on a spot market basis, the required consumables are typically provided by the Company and the customer is billed for those consumables at cost plus an agreed-upon markup. For services performed on a contractual basis, when the consumables are provided by the Company, the customer typically is billed for those consumables at a negotiated contractual rate. When consumables are supplied by the customer, the Company typically charges handling fees based on the amount of consumables used.

Other Completion Services Revenue. The Company generates revenue from its R&T department, which 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. Revenue is recognized upon the completion, delivery and customer acceptance of each order of parts and components.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Well Support Services Segment

Rig Services Revenue. Through its rig services line, the Company provides workover and well servicing rigs that are primarily used for routine repair and maintenance of oil and gas wells, re-drilling operations and plugging and abandonment operations. These services are provided on an hourly basis at agreed upon spot market rates. Revenue is recognized and a field ticket is generated upon the earliest of the completion of a job or at the end of each day. A rig services job can last anywhere from a few hours to multiple days depending on the type of work being performed. The field ticket includes the base hourly rate charge and, if applicable, charges for additional personnel or equipment not contemplated in the base hourly rate. The field ticket may also include charges for the mobilization and set-up of equipment,

Fluids Management Services Revenue. Through its fluids management service line, the Company primarily provides storage, transportation and disposal services for fluids used in the drilling, completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour or per load basis, or on the basis of quantities sold or disposed. Revenue is recognized upon the completion of each job or load, or delivered product, based on a completed field ticket.

Other Special Well Site Services Revenue. Through its other special well site service line, the Company primarily provides fishing, contract labor, and tool rental services for completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour or on the basis of rental days per month. Revenue is recognized based on a field ticket issued upon the completion of each job or on a monthly billing for rental services provided.

With respect to its artificial lift applications, the Company generates revenue primarily from the sale of manufactured equipment and products. Revenue is recognized upon the completion, delivery and customer acceptance of each order.

Other Services Segment

Revenue within the Other Services Segment was generated from certain of the Company’s smaller, non-core service lines that were divested in 2016, such as the Company's specialty chemical business, equipment manufacturing and repair business and international coiled tubing operations in the Middle East. In line with the discontinuance of these small, ancillary service lines and divisions, subsequent to the year ended December 31, 2016, the Company is now disclosing two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period.

Share-Based Compensation. The Company’s share-based compensation plans provide the ability to grant equity awards to the Company’s employees, consultants and non-employee directors. As of December 31, 2017, only nonqualified stock options, restricted shares and performance awards had been granted under such plans. The fair value of restricted stock grants is based on the closing price of C&J’s common stock on the grant date. The Company values option grants based on the grant date fair value using the Black-Scholes option-pricing model, and the Company values equity 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. The Company recognizes share-based compensation expense on a straight-line basis over the requisite service period for the entire award. Further information regarding the Company’s share-based compensation arrangements and the related accounting treatment can be found in Note 7 - Share-Based Compensation.

Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable and accounts payable. The recorded values of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values given the short-term nature of these instruments.

Equity Method Investments. The Company has investments in joint ventures which are accounted for under the equity method of accounting as the Company has the ability to exercise significant influence over operating and financial policies of the joint venture. Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions and material intercompany transactions. Under the equity method, original investments are recorded at cost and adjusted by the Company’s share of undistributed earnings and losses of these investments. The Company eliminates all significant intercompany transactions, including the intercompany portion of transactions with equity method investees, from the consolidated financial results.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The carrying value of the Company's equity method investments at December 31, 2017 and December 31, 2016 was $2.8 million and $9.0 million, respectively, and is included in other noncurrent assets on the consolidated balance sheets. The Company’s share of the net income (loss) from the unconsolidated affiliates was approximately ($0.1) million, ($5.7) million and $0.5 million the years ended December 31, 2017, 2016 and 2015 respectively and is included in other income (expense), net, on the consolidated statements of operations.

Income Taxes. The Company is subject to income and other similar taxes in all areas in which they 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.

The Company accounts 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 Company has federal, state and international net operating losses ("NOLs") carried forward from prior years that will expire in the years 2020 through 2037. 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, the Company 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, the Company believes it experienced an ownership change for purposes of Section 382 of the Code because of its Restructuring Plan and in addition experienced a subsequent ownership change on or about June 30, 2017. Consequently, its pre-change NOLs are subject to an annual limitation (See Note 2 - 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 the Company's NOL carryforwards if it is 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 the Company's pre-change NOL carryforwards to expire unused.

The Company recognizes 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, 2017, the Company recorded an income tax benefit of $6.5 million related to a decrease in the estimate of the reserve for unrecognized tax benefits relating to uncertain tax positions. The decrease resulted from the effect of changes in the application of relevant withholding tax provisions under applicable local country treaties related to certain of the Company's foreign subsidiaries. As of December 31, 2017, the Company has no uncertain tax positions.

Earnings Per Share. Basic earnings per share is based on the weighted average number of common shares (“common shares”) outstanding during the applicable period and excludes shares subject to outstanding stock options and shares of restricted stock. Diluted earnings per share is computed based on the weighted average number of common shares outstanding during the period plus, when their effect is dilutive, incremental shares consisting of shares subject to outstanding stock options and restricted stock.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is a reconciliation of the components of the basic and diluted earnings per share calculations for the applicable periods:



	Successor		Predecessor
	(In thousands, except per share amounts)
	Years Ended December 31,
	2017		2016			2015

Numerator:
Net income (loss) attributed to common stockholders	$	22,457	$	(944,289	)	$	(872,542	)
Denominator:
Weighted average common shares outstanding - basic	61,208		118,305			102,853
Effect of potentially dilutive securities:
Stock options	—		—			—
Restricted stock	4		—			—
Warrants	248		—			—
Weighted average common shares outstanding - diluted	61,460		118,305			102,853
Net income (loss) per common share:
Basic	$	0.37	$	(7.98	)	$	(8.48	)
Diluted	$	0.37	$	(7.98	)	$	(8.48	)

A summary of securities excluded from the computation of basic and diluted earnings per share is presented below for the applicable periods:



	Successor	Predecessor
	(In thousands)
	Years Ended December 31,
	2017	2016	2015
Basic earnings per share:
Unvested restricted stock	537	1,529	2,610
Diluted earnings per share:
Anti-dilutive stock options	235	4,808	3,661
Anti-dilutive warrants	—	—	—
Anti-dilutive restricted stock	524	1,490	2,125
Potentially dilutive securities excluded as anti-dilutive	759	6,298	5,786

On January 6, 2017, the Debtors substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. As part of the transactions undertaken pursuant to the Restructuring Plan, all of the existing shares of the Predecessor common equity that were used in the above earnings per share calculations of the Predecessor were canceled as of the Plan Effective Date.

Recent Accounting Pronouncements.

In May 2014, the FASB issued a comprehensive new revenue recognition standard, Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09") that will supersede existing revenue recognition guidance under U.S. GAAP. In August 2015, the FASB issued an accounting standards update for a one-year deferral of the revenue recognition standard's effective date for all entities, which changed the effectiveness to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for the following transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

standard’s application impact to individual financial statement line items. The Company adopted this new accounting standard on January 1, 2018, and upon adoption, the Company incorporated the modified retrospective approach as its transition method. The approach included performing a detailed review of key contracts representative of the Company’s different service lines and comparing historical accounting policies and practices to the new standard. Based on this assessment, the Company has concluded the adoption of this new accounting standard will not have a material impact on the consolidated financial statements.

In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory ("ASU 2015-11"), which changes the measurement principle for inventory from the lower of cost or market to lower of cost and net realizable value. ASU 2015-11 is part of the FASB’s simplification initiative and applies to entities that measure inventory using a method other than last-in, first-out ("LIFO") or the retail inventory method. The Company adopted ASU 2015-11 on January 1, 2017 prospectively and the adoption had no effect on the consolidated financial statements.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes ("ASU 2015-17”). ASU 2015-17 amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as non-current on the balance sheet. The Company adopted ASU 2015-17 on January 1, 2017 prospectively and no prior periods have been restated to conform to the new presentation. The adoption had no effect on the Company's results of operations or financial position.

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. The Company is currently evaluating the impact of adopting this new accounting standard on its consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting ("ASU 2016-09"), to simplify certain provisions in stock compensation accounting, including the simplification of accounting for a stock payment's tax consequences. The ASU amends the guidance for classifying awards as either equity or liabilities, allows companies to estimate the number of stock awards they expect to vest, and revises the tax withholding requirements for stock awards. The amendments in ASU No. 2016-09 are effective for public companies for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, and early application is permitted. The Company adopted ASU 2016-09 on January 1, 2017 prospectively and the adoption had no effect on the Company's results of operations or financial position.

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. The Company is currently evaluating the impact this standard will have on its consolidated financial statements.

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. The Company adopted this new accounting standard on January 1, 2018. The Company anticipates a cumulative effect adjustment as a reduction to retained earnings of approximately $13.2 million will occur as a result of the Company's adoption of ASU 2016-16.

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 a drop in value. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019 and early adoption is permitted. The Company does not expect the adoption of this new accounting standard to have a significant impact on its consolidated financial statements.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 - Chapter 11 Proceeding and Emergence

Overview

On July 8, 2016, the Debtors, including C&J Corporate Services (Bermuda) Ltd. (together with the Predecessor, the “Bermudian Entities”), C&J Energy Production Services-Canada Ltd. and Mobile Data Technologies Ltd. (together, the “Canadian Entities”), entered into a Restructuring Support and Lock-Up Agreement (the “Restructuring Support Agreement”), with certain lenders (the “Supporting Lenders”) holding approximately 90.0% of the secured claims and interests arising under the Credit Agreement, dated as of March 24, 2015 (as amended and otherwise modified, the “Original Credit Agreement”). The Restructuring Support Agreement contemplated the implementation of a financial restructuring of the Company, including the elimination of all amounts owed under the Original Credit Agreement through a complete debt-to-equity conversion and a re-investment in the Company through an equity rights offering. This financial restructuring was effectuated through the Restructuring Plan under Chapter 11 of the Bankruptcy Code.

To implement the Restructuring Support Agreement, on July 20, 2016 (the “Petition Date”), the Debtors filed voluntary petitions for reorganization (the “Bankruptcy Petitions”) seeking relief under the provisions of Chapter 11 of the Bankruptcy Code with the United States Bankruptcy Court in the Southern District of Texas, Houston Division (the “Bankruptcy Court”), and also commenced ancillary proceedings in Canada on behalf of the Canadian Entities and a provisional liquidation proceeding in Bermuda on behalf of the Bermudian Entities. The Chapter 11 Proceeding was being administered under the caption “In re: CJ Holding Co., et al., Case No. 16-33590”. Throughout the Chapter 11 Proceeding, the Debtors continued operations and management of their assets in the ordinary course as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

In accordance with the Restructuring Support Agreement, the Debtors filed the Restructuring Plan and related disclosure statement (the “Disclosure Statement”) with the Bankruptcy Court on August 19, 2016, with a first amendment to the Restructuring Plan filed on September 28, 2016 and a second amendment filed on November 3, 2016. On November 4, 2016, the Bankruptcy Court approved the Disclosure Statement, finding that the Disclosure Statement contained adequate information as required by the Bankruptcy Code. The Debtors then launched a solicitation of acceptances of the Restructuring Plan, as required by the Bankruptcy Code. On December 16, 2016, an order confirming the Restructuring Plan was entered by the Bankruptcy Court. On the Plan Effective Date, the Debtors substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. As part of the transactions undertaken pursuant to the Restructuring Plan, as of the Plan Effective Date, the Successor was formed, the Predecessor's equity was canceled, the Predecessor transferred all of its assets and operations to the Successor and the Predecessor was subsequently dissolved. As a result, the Successor became the successor issuer to the Predecessor.

The key terms of the restructuring included in the Restructuring Plan were as follows:


•	Debt-to-equity Conversion: As of the Plan Effective Date, the Supporting Lenders were issued new common equity (“New Equity”) in the Successor, as the ultimate parent company of the reorganized Debtors, and all of the existing shares of the Predecessor's common equity were canceled.

•

The Rights Offering, Backstop Commitment: The Company offered its secured lenders the right to purchase New Equity in an amount of up to $200.0 million as part of the approved Restructuring Plan (the “Rights Offering”). Certain of the Supporting Lenders (the “Backstop Parties”) agreed to backstop the full amount pursuant to a Backstop Commitment Agreement, in exchange for a commitment premium of 5.0% of the $200.0 million committed amount payable in New Equity to the Backstop Parties (the “Backstop Fee”). The Rights Offering was consummated on the Plan Effective Date and the shares were issued at a price that reflects a discount of 20.0% to the Restructuring Plan value, which was $750.0 million.

•

DIP Facility: Certain of the Supporting Lenders (the “DIP Lenders”) provided a superpriority secured delayed draw term loan facility to the Predecessor in an aggregate principal amount of up to $100.0 million (the “DIP Facility”). As further discussed below, on July 25, 2016, the Bankruptcy Court entered an order approving the Debtors’ entry into the DIP Facility on an interim basis, pending a final hearing. On July 29, 2016, the Debtors entered into a superpriority secured debtor-in-possession credit agreement, among the Debtors, the DIP Lenders and Cortland Capital Market Services LLC, as Administrative Agent (the “DIP Credit Agreement”), which set forth the terms and conditions of the DIP Facility. On September 25, 2016,

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the Bankruptcy Court entered a final order approving entry into the DIP Facility and DIP Credit Agreement. The Company repaid all amounts outstanding under the DIP Facility on the Plan Effective Date using proceeds from the Rights Offering.

•

The New Credit Facility: The Successor and certain of its subsidiaries, as borrowers (the “Borrowers”), entered into a revolving credit and security agreement (the “New Credit Facility”) dated the Plan Effective Date with a maturity date of January 6, 2021, with PNC Bank, National Association, as administrative agent (the “Agent”). The Borrowers subsequently amended and restated the New Credit Facility in full pursuant to an amended and restated credit and security agreement (the “Amended Credit Facility”) dated May 4, 2017, with the Agent and the lenders party thereto. The Amended Credit Facility allows the Borrowers to incur revolving loans in an aggregate amount up to the lesser of $200.0 million and a borrowing base, which borrowing base is based upon the value of the Borrowers’ accounts receivable and inventory. The Amended Credit Facility also provides for the issuance of letters of credit, which would reduce borrowing capacity thereunder. The maturity date of the Amended Credit Facility is May 4, 2022.

•

The New Warrants: As of the Plan Effective Date, the Company agreed to issue new seven-year warrants exercisable on a net-share settled basis into up to 6.0% of the New Equity at a strike price of $27.95 per warrant (the “New Warrants”). New Warrants representing up to 2.0% of the New Equity were issued to existing holders of Predecessor common equity as a result of such holders voting as a class to accept the Restructuring Plan, and the remaining New Warrants representing up to 4.0% of the New Equity were issued to a third party who acquired them from the representative for the Debtors' general unsecured creditors.

•

Distributions: The DIP Lenders received payment in full in cash on the Plan Effective Date from cash on hand and proceeds from the Rights Offering. The Supporting Lenders received all of the New Equity, subject to dilution on account of the Management Incentive Plan (as defined below), the Rights Offering, the Backstop Fee and the New Warrants, along with all of the subscription rights under the Rights Offering. Under the Restructuring Plan, mineral contractor claimants have or will be paid in full in the ordinary course of business. Additionally, subject to the terms of the Restructuring Plan, certain other unsecured claimants will share in a $33.0 million cash recovery pool, plus a portion of the New Warrants, as described above.


•	Management Incentive Plan: 10.0% of the New Equity was reserved for a management incentive program to be issued to management of the Company after the Plan Effective Date from time to time at the discretion of the board of the reorganized Company (the “Management Incentive Plan”). See Note 7 - Share-Based Compensation for additional information regarding the Management Incentive Plan.


•	Governance: The board of the Successor was appointed by the Supporting Lenders and includes the Successor's Chief Executive Officer.

Liabilities Subject to Compromise

As of December 31, 2016, the Company had segregated liabilities and obligations whose treatment and satisfaction were dependent on the outcome of its reorganization under the Chapter 11 Proceeding and had classified these items as liabilities subject to compromise. Generally, all actions to enforce or otherwise effect repayment of pre-petition liabilities of the Debtors, as well as all pending litigation against the Debtors, were subject to the Chapter 11 Proceeding. Liabilities subject to compromise includes only those liabilities that are obligations of the Debtors and excludes the obligations of the Predecessor's non-debtor subsidiaries.

Principal and accrued interest owed to the Supporting Lenders as of the Petition Date were settled via the issuance of New Equity under the Restructuring Plan. Interest expense incurred subsequent to the Petition Date was not accrued since it was not treated as an allowed claim under the Restructuring Plan. For the year ended December 31, 2016, the Company did not accrue interest totaling $60.5 million under the Original Credit Agreement subsequent to the Petition Date.

As of December 31, 2016, the Company classified the entire principal balance of the Revolving Credit Facility, the Five-Year Term Loans and the Seven-Year Term Loans (see Note 4 - Debt for defined terms), as well as interest that was accrued but unpaid as of the Petition Date, as liabilities subject to compromise in accordance with ASC 852 - Reorganizations. The components of liabilities subject to compromise were as follows (in thousands):

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	December 31, 2016
Revolving Credit Facility	$	284,400
Five-Year Term Loans	569,250
Seven-Year Term Loans	480,150
Total debt subject to compromise	1,333,800
Accrued interest on debt subject to compromise	37,516
Accounts payable and other estimated allowed claims	60,780
Related party payables	13,250
Total liabilities subject to compromise	$	1,445,346

Reorganization Items

The Company classifies all income, expenses, gains or losses that were incurred or realized as a result of the Chapter 11 Proceeding as reorganization items in its consolidated statements of operations. In addition, the Company reports professional fees and related costs associated with and incurred during the Chapter 11 Proceeding as reorganization items. The components of reorganization items are as follows (in thousands):



	Year Ended December 31, 2016			On January 1, 2017
Gain on settlement of liabilities subject to compromise	$	—		$	666,399
Net loss on fresh start fair value adjustments	—			(358,557		)
Professional fees	(41,240		)	(13,435		)
Contract termination settlements	(20,383		)	—
Revision of estimated claims	(782		)	—
Related party settlement	5,226			—
Vendor claims adjustment	1,849			(438		)
Total reorganization items	$	(55,330	)	$	293,969

While the Company's emergence from bankruptcy is complete, certain administrative activities will continue under the authority of the Bankruptcy Court for the next several months.

Note 3 - Fresh Start Accounting

The Company adopted Fresh Start accounting on the Plan Effective Date in connection with the Company's emergence from bankruptcy. Although the effective date of the Restructuring Plan was January 6, 2017, the Company accounted for the consummation of the Restructuring Plan as if it had occurred on the Fresh Start Reporting Date, January 1, 2017 and implemented Fresh Start reporting as of that date. The adoption of Fresh Start accounting resulted in a new reporting entity, the Successor, for financial reporting purposes. The presentation is analogous to that of a new business entity such that on the Plan Effective Date the Successor's consolidated financial statements reflect a new capital structure with no beginning retained earnings or deficit and a new basis in the identifiable assets and liabilities assumed which includes the elimination of Predecessor accumulated depreciation and accumulated amortization. Upon the Company's emergence from the Chapter 11 Proceeding, the Company qualified for and adopted Fresh Start accounting in accordance with the provisions set forth in ASC 852 based on the following two conditions: (i) holders of existing voting shares of the Predecessor immediately before the Plan Effective Date received less than 50.0% of the voting shares of the Successor and (ii) the reorganization value of the Successor was less than its post-petition liabilities and estimated allowed claims.

As part of Fresh Start accounting, the Company was required to determine the reorganization value of the Successor upon emergence from the Chapter 11 Proceeding. Reorganization value approximates the fair value of the entity, before considering liabilities, and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring. The fair value of the Successor's assets was determined with the assistance of a third-party valuation expert who used available comparable market data and quotations, discounted cash flow analysis, and other methods in determining the appropriate asset fair values. The reorganization value was allocated to the Company's individual assets based on their estimated fair values.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Enterprise value, which was used to derive reorganization value, represents the estimated fair value of an entity’s capital structure which generally consists of long term debt and stockholders’ equity. The Successor’s enterprise value was approved by the Bankruptcy Court in support of the Restructuring Plan and was not to exceed $750.0 million, which represented the mid-point of a determined range of $600.0 million to $900.0 million. The Successor's enterprise value of $750.0 million was based upon $725.9 million of New Equity and New Warrants as approved by the Bankruptcy Court and $24.1 million of other liabilities that were not eliminated or discharged under the Restructuring Plan. The Successor's enterprise value was determined with the assistance of a separate third-party valuation expert who used available comparable market data and quotations, discounted cash flow analysis and other internal financial information and projections. This enterprise value combined with the Company’s Rights Offering was the basis for deriving equity value. The Company’s estimates of fair value are inherently subject to significant uncertainties and contingencies beyond its control. Accordingly, there can be no assurance that the estimates, assumptions, valuations, appraisals and financial projections will be realized, and actual results could vary materially. Moreover, the market value of the Company’s common stock subsequent to its emergence from bankruptcy may differ materially from the equity valuation derived for accounting purposes.

Machinery and Equipment

The fair value of machinery and equipment was estimated with the assistance of the third-party valuation expert, and the market approach, the cost approach, and the income approach were considered for each individual asset. The market approach and the cost approach were the primary approaches that were relied upon to value these assets. Although the income approach was not applied to value the machinery and equipment assets individually, the Company did consider the earnings of the reporting unit within which each of these assets reside. Because more than one approach was used to develop a valuation, the various approaches were reconciled to determine a final value conclusion.

Under the cost approach, the valuation estimate was based upon a determination of replacement cost new ("RCN"), reproduction cost new ("CRN"), or a combination of both. Once the RCN and CRN estimates were adjusted for physical and functional conditions, they were then compared to market data and other indications of value, where available, to confirm results obtained by the cost approach. Where direct RCN estimates were not available or deemed inappropriate, the CRN for machinery and equipment was estimated using the indirect, or trending, method in which percentage changes in applicable price indices were applied to historical costs to convert them into indications of current costs. To estimate the CRN amounts, inflation indices from established external sources were then applied to historical costs to estimate the CRN for each such asset.

The Company also developed a cost approach when market information was not available, or a market approach was deemed inappropriate. In doing so, an indicated value was derived by deducting physical deterioration from the RCN or CRN of each identifiable asset. Physical deterioration is the loss in value or usefulness of a property due to the using up or expiration of its useful life caused by wear and tear, deterioration, exposure to various elements, physical stresses, and similar factors.

Under the market approach, the valuation estimate was based upon an analysis of recent sales transactions for comparable assets and took into account physical, functional and economic conditions. Where comparable sales transactions could not be reasonably obtained, the Company utilized the percent of cost technique under the market approach, which takes into consideration general sales, sales listings, and auction data for each major asset category. This information was then used in conjunction with each asset’s effective age to develop ratios between the sales price and RCN or CRN of similar asset types. A market-based depreciation curve was then developed and applied to asset categories where sufficient sales and auction information existed.

Economic obsolescence related to machinery and equipment was also considered and was applied to stacked and underutilized assets based upon the status of the asset. Economic obsolescence was also considered in situations in which the earnings of the applicable business segment in which the assets are employed suggest economic obsolescence. When penalizing assets for economic obsolescence, an additional economic obsolescence penalty was levied, while considering scrap value to be the floor value for an asset.

Land, Buildings and Leasehold Improvements

The fair value estimates of the real property assets were estimated with the assistance of the third-party valuation expert, and the market approach, the cost approach, and the income approach were considered for each of the Company's significant real property assets. The Company primarily relied upon the market and cost approaches.

In valuing the fee simple interest in the land, the Company utilized the sales comparison approach under the market approach. The sales comparison approach estimates value based upon the price in which other purchasers and sellers have

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

agreed to transact for comparable properties. This approach is based on the principle of substitution, which states that the limits of prices, rents and rates tend to be set by the prevailing prices, rents and rates of equally desirable substitutes. In conducting the sales comparison approach, data was gathered on comparable properties and adjustments were made for factors including market conditions, size, access/frontage, zoning, location, and conditions of sale. Greatest weight was typically given to the comparable sales in proximity and similar in size to each of the owned sites.

In valuing the fee simple interest in buildings and leasehold improvements, the Company utilized the direct and indirect methods of the cost approach. For the direct method cost approach analysis, the Company first had to determine the RCN. In order to estimate the RCN of the buildings and leasehold improvements, various factors were considered including building size, year built, number of stories, and the breakout of the space, property history, maintenance history, and insurable value costs. For the indirect method cost approach, the Company first had to estimate a CRN for leasehold improvements being valued via the indirect, or trending, method of the cost approach. To estimate the CRN amounts, the Company applied published inflation indices obtained from third-party sources to each asset’s historical cost to convert the known cost into an indication of current cost.

Once the RCN and CRN of the buildings and leasehold improvements was computed, the Company estimated an allowance for physical depreciation for the buildings and leasehold improvements based upon their respective age.

Intangible Assets

The financial information used to estimate the fair values of intangible assets was consistent with the information used in estimating the Company’s enterprise value. Tradenames were valued primarily utilizing the relief from royalty method of the income approach. Significant inputs and assumptions included remaining useful lives, the forecasted revenue streams, applicable royalty rates, tax rates, and applicable discount rates. Customer relationships were considered in the analysis, but based on the valuation under the excess earnings methodology, no value was attributed to customer relationships.

The following table reconciles the enterprise value to the estimated fair value of the Successor common stock as of the Fresh Start Reporting Date (in thousands):



Enterprise value	$	750,000
Add: Cash and cash equivalents	181,242
Less: Emergence costs settled in cash post-emergence	(5,378		)
Fair value of New Equity and New Warrants, including Rights Offering	925,864
Less: Rights Offering proceeds	(200,000		)
Less: Fair value of New Warrants	(20,385		)
Fair value of Successor common stock, prior to Rights Offering	$	705,479

Shares outstanding on January 1, 2017, prior to Rights Offering shares	39,999,997
Per share value	$	17.64

The following table reconciles the enterprise value to the reorganization value of the Successor assets on the Effective Date (in thousands):



Enterprise value	$	750,000
Add: Cash and cash equivalents	181,242
Less: Emergence costs settled in cash post-emergence	(5,378		)
Add: Other current liabilities	165,501
Add: Other long-term liabilities and deferred tax liabilities	22,666
Reorganization value of Successor assets	$	1,114,031

The following table summarizes the impact of the reorganization and the Fresh Start accounting adjustments on the Company's consolidated balance sheet on the Fresh Start Reporting Date. The reorganization value has been allocated to the assets acquired based upon their estimated fair values, as shown below. The estimated fair values of certain assets and

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

liabilities, including property, plant and equipment, other intangible assets, taxes (including uncertain tax positions), and contingencies required significant judgments and estimates (in thousands):



	Predecessor			Reorganization Adjustments				Fresh Start Adjustments				Successor

ASSETS
Current assets:
Cash and cash equivalents	$	64,583		$	116,659		(a)	$	—			$	181,242
Accounts receivable	137,222			—				—				137,222
Inventories, net	54,471			—				—				54,471
Prepaid and other current assets	37,392			—				—				37,392
Deferred tax assets	6,020			—				—				6,020
Total current assets	299,688			116,659				—				416,347
Property, plant and equipment, net	950,811			—				(350,314		)	(h)	600,497
Other assets:
Intangible assets, net	76,057			—				(15,657		)	(h)	60,400
Deferred financing costs	—			2,248			(b)	—				2,248
Other noncurrent assets	35,045			—				(506		)	(h)	34,539
Total assets	$	1,361,601		$	118,907			$	(366,477	)		$	1,114,031
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	75,193		$	16,848		(c)	$	—			$	92,041
Payroll and related costs	18,287			—				—				18,287
Accrued expenses	59,129			(5,985		)	(c)	—				53,144
DIP Facility	25,000			(25,000		)	(d)	—				—
Other current liabilities	3,026			—				(997		)	(i)	2,029
Total current liabilities	180,635			(14,137		)		(997		)		165,501
Deferred tax liabilities	15,613			—				(4,613		)	(j)	11,000
Other long-term liabilities	18,577			—				(6,911		)	(i)	11,666
Total liabilities not subject to compromise	214,825			(14,137		)		(12,521		)		188,167
Liabilities subject to compromise	1,445,346			(1,445,346		)	(e)	—				—
Commitments and contingencies
Stockholders' equity:
Common stock	1,195			(640		)	(f)	—				555
Additional paid-in capital	1,009,426			926,504			(f)	(1,010,621		)	(k)	925,309
Accumulated other comprehensive loss	(2,600		)	—				2,600			(k)	—
Retained earnings (deficit)	(1,306,591		)	652,526			(g)	654,065			(l)	—
Total stockholders' equity (deficit)	(298,570		)	1,578,390				(353,956		)	(l)	925,864
Total liabilities and stockholders' equity	$	1,361,601		$	118,907			$	(366,477	)		$	1,114,031

Reorganization adjustments

(a) Represents the reorganization adjustment to cash and cash equivalents (in thousands):

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Cash settlement of general unsecured and other reinstated claims	$	(33,898	)
Payment of professional fees and success fees paid	(21,657		)
Repayment of DIP Facility borrowing and accrued interest	(25,538		)
Proceeds from the Rights Offering	200,000
Payment of deferred financing costs related to the New Credit Facility	(2,248		)
Net impact to cash and cash equivalents	$	116,659

(b) Represents deferred loan costs associated with the closing of the New Credit Facility.



Accounts payable:
Pre-petition liabilities related to contract cures, 503(b)(9) claims and critical vendors	$	16,848

Accrued expenses:
Settlement of professional fees	$	(10,135	)
Reinstate liability for acquisition holdback	4,100
Settlement of accrued interest related to the DIP Facility	(538		)
Other accrued expenses	588
Net impact to accrued expenses	$	(5,985	)

(d) Represents the repayment of the DIP Facility.

(e) Represents the settlement of liabilities subject to compromise in accordance with the Restructuring Plan (in thousands):




Fair value of Successor common stock	$	(705,479	)
Fair value of New Warrants issued per the Restructuring Plan	(20,385		)
Fair value of reinstated accounts payable and accrued liabilities to be settled in cash	(20,083		)
General unsecured creditor claims settled in cash	(33,000		)
Gain on settlement of liabilities subject to compromise	(666,399		)
Net impact to liabilities subject to compromise	$	(1,445,346	)

(f) Represents the reorganization adjustments to common stock and additional paid in capital (in thousands):




Common stock:
Cancellation of Predecessor common shares	$	(1,195	)
Issuance of Successor common stock	555
Net impact to common stock	$	(640	)

Additional paid in capital:
Fair value of Successor common stock	$	705,479
Fair value of New Warrants issued per the Restructuring Plan	20,385
Proceeds from the Rights Offering	200,000
Cancellation of Predecessor common shares	1,195
Issuance of Successor common stock	(555		)
Net impact to additional paid in capital	$	926,504

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(g) Represents the reorganization adjustments to retained deficit (in thousands):




Gain on settlement of liabilities subject to compromise	$	666,399
Accrual of success fee	(13,435		)
Adjustment for other expenses	(438		)
Net impact to retained deficit	$	652,526

Fresh Start adjustments

(h) Represents the Fresh Start accounting adjustments based upon the individual asset fair values.

(i) Represents the accelerated recognition of deferred gain balances of the Predecessor.

(j) Represents the tax effect of the above Fresh Start accounting adjustments.

(k) Represents the adjustment to Predecessor additional paid-in capital as a result of the elimination of Predecessor retained deficit and accumulated other comprehensive loss in accordance with ASC 852.

(l) Represents the income statement impacts of the revaluation loss of $354.0 million, after tax, and the elimination of the resulting retained deficit balance in accordance with ASC 852.

Note 4 - Debt

Debt consisted of the following as of December 31, 2017 and 2016 (in thousands):



	Successor		Predecessor
	As of December 31,
	2017		2016
Revolving Credit Facility	$	—	$	284,400
Five-Year Term Loans	—		569,250
Seven-Year Term Loans	—		480,150
Total debt	—		1,333,800
Less: liabilities subject to compromise	—		(1,333,800		)
Long-term debt and capital lease obligations	$	—	$	—

DIP Facility	$	—	$	25,000

On July 20, 2016, the Debtors filed Bankruptcy Petitions in the Bankruptcy Court seeking relief under Chapter 11 of the Bankruptcy Code under the caption “In re: CJ Holding Co., et al., Case No. 16-33590.” The filing of the Bankruptcy Petitions constituted an event of default with respect to the Original Credit Agreement. As a result, the Company’s pre-petition secured indebtedness under the Original Credit Agreement became immediately due and payable and any efforts to enforce such payment obligations were automatically stayed as a result of the Chapter 11 Proceeding. As of December 31, 2016, $1.3 billion of debt under the Company's Credit Agreement was classified as liabilities subject to compromise.

Additional information regarding the Chapter 11 Proceeding is included in Note 2 - Chapter 11 Proceeding and Emergence.

Amended Credit Facility

On January 6, 2017, in connection with the emergence from bankruptcy, the Company entered into the New Credit Facility, and subsequently on May 4, 2017, entered into the Amended Credit Facility.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Amended Credit Facility allows the Borrowers, to incur revolving loans in an aggregate amount up to the lesser of $200.0 million and a borrowing base, which borrowing base is based upon the value of the Borrowers’ accounts receivable and inventory, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion. The Amended Credit Facility also provides for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Amended Credit Facility is May 4, 2022.

If at any time the amount of loans and other extensions of credit outstanding under the Amended Credit Facility exceed the borrowing base, the Borrowers may be required, among other things, to prepay outstanding loans immediately.

At the Borrowers’ election, interest on borrowings under the Amended Credit Facility will be determined by reference to either LIBOR plus an applicable margin of 2.0% or an “alternate base rate” plus an applicable margin of 1.0%. These margins are subject to a monthly step-up of 0.25% in the event that average excess availability under the Amended Credit Facility is less than 37.5% of the total commitment, and a monthly step-down of 0.25% in the event that average excess availability under the Amended Credit Facility is equal to or greater than 62.5% of the total commitment. 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. The Borrowers will also be required to pay a fee on the unused portion of the Amended Credit Facility equal to (i) 0.75% in the event that utilization is less than 25.0% of the total commitment, (ii) 0.50% in the event utilization is equal to or greater than 25% of the total commitment but less than 50% of the total commitment and (iii) 0.375% in the event that utilization is equal to or greater than 50% of the total commitment.

The Amended Credit Facility also contains a financial covenant that requires the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 if, as of any month-end, liquidity is less than $40.0 million.

As of December 31, 2017, the Company was in compliance with all financial covenants.

DIP Facility

On July 29, 2016, the Predecessor entered into the DIP Credit Agreement with the other Debtors, the DIP Lenders and Cortland Capital Market Services LLC, as administrative agent.

The borrowers under the DIP Facility were the Predecessor and CJ Holding Co. All obligations under the DIP Facility were guaranteed by the Company’s subsidiaries that were debtors in the Bankruptcy cases. Borrowings under the DIP Credit Agreement were generally secured by superpriority priming liens on substantially all of the assets of the borrowers and guarantors.

Amounts outstanding under the DIP Facility bore interest based on, at the option of the borrower, LIBOR or an alternative base rate, plus an applicable margin equal to 9.0% in the case of LIBOR loans and 8.0% in the case of base rate loans. The alternative base rate was equal to the highest of (i) the published ‘prime rate’, (ii) the Federal Funds Effective Rate (as defined in the DIP Credit Agreement) plus 0.5% and (iii) LIBOR plus 1.0%. The DIP Facility also required that the Company pay various fees to the DIP Lenders, including a commitment fee equal to 5.0% of the unused commitments thereunder. The DIP Facility was scheduled to mature on March 31, 2017.

In accordance with the Restructuring Plan, on the Plan Effective Date, the Company repaid all amounts outstanding under the DIP Facility with the proceeds from the Rights Offering and the DIP Facility was canceled and discharged.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Predecessor Credit Agreements

On March 24, 2015, in connection with the closing of the Nabors Merger, the Predecessor entered into the Original Credit Agreement. The Original Credit Agreement provided for senior secured credit facilities in an aggregate principal amount of $1.66 billion, consisting of (i) a revolving credit facility (“Revolving Credit Facility” or the “Revolver”) in the aggregate principal amount of $600.0 million and (ii) a term loan B facility (“Term Loan B Facility”) in the aggregate principal amount of $1.06 billion. The Company simultaneously repaid all amounts outstanding and terminated Old C&J’s prior credit agreement; no penalties were due in connection with such repayment and termination. All obligations under the Original Credit Agreement were guaranteed by the Predecessor’s wholly-owned domestic subsidiaries, other than immaterial subsidiaries.

On September 29, 2015, the Company obtained and the Predecessor entered into a waiver and amendments to the Original Credit Agreement, which, among other things, suspended certain financial covenants set forth in the Original Credit Agreement. The suspension of these financial covenants commenced with the fiscal quarter ending September 30, 2015 and would have lasted through the fiscal quarter ending June 30, 2017.

On May 10, 2016, the Company obtained a temporary limited waiver agreement from certain of the lenders pursuant to which, effective as of March 31, 2016, such lenders agreed to not consider a breach of the Minimum Cumulative Consolidated EBITDA (as defined in the Original Credit Agreement) covenant measured as of March 31, 2016 an event of default through May 31, 2016.

On May 31, 2016, the Company obtained and the Predecessor entered into the Forbearance Agreement with certain of the lenders pursuant to which, among other things, such lenders agreed not to pursue default remedies against the Company with respect to its breach of the Minimum Cumulative Consolidated EBITDA covenant or certain specified payment defaults.

On June 30, 2016, this forbearance was extended through July 17, 2016 pursuant to the Second Forbearance Agreement, and prior to the termination of the Second Forbearance Agreement, this forbearance period was once again extended through July 20, 2016. The Second Forbearance Agreement provided that the forbearance would terminate upon the occurrence of certain events, including the failure of the Predecessor to enter into the Restructuring Support Agreement on or prior to July 8, 2016. On July 8, 2016, the Predecessor entered into the Restructuring Support Agreement with the Supporting Lenders. The Restructuring Support Agreement contemplated the implementation of a restructuring of the Company through a debt-to-equity conversion and Rights Offering, which transaction was effectuated through the Restructuring Plan.

On July 20, 2016, the Debtors filed Bankruptcy Petitions in the Bankruptcy Court seeking relief under Chapter 11. Additional information, including definitions of capitalized defined terms, regarding the Chapter 11 Proceeding is included in Note 2 - Chapter 11 Proceeding and Emergence.

Revolving Credit Facility

The Revolver was scheduled to mature on March 24, 2020 (except that if any Five-Year Term Loans (as defined herein) had not been repaid prior to September 24, 2019, the Revolver was scheduled to mature on September 24, 2019). Borrowings under the Revolver were non-amortizing. Amounts outstanding under the Revolver bore interest based on, at the option of the borrower, LIBOR or an alternative base rate, plus an applicable margin determined pursuant to a pricing grid based on the ratio of consolidated total indebtedness of C&J and its subsidiaries to Consolidated EBITDA of C&J and its subsidiaries for the most recent four fiscal quarter period for which financial statements are available.

On July 20, 2016, the Debtors filed the Bankruptcy Petitions which constituted an event of default under the Original Credit Agreement and accelerated the Revolver and Term Loan B Facility indebtedness to become immediately due and payable. On the Plan Effective Date, pursuant to the Restructuring Support Agreement entered into on July 8, 2016, holders of the Revolver and Term Loan B Facility received their pro rata share of 100.0% of the New Equity in the Successor, subject to dilution from the issuance of New Equity on account of the Management Incentive Plan, the Rights Offering, the Backstop Fee and the New Warrants as discussed further in Note 2 - Chapter 11 Proceeding and Emergence.

Term Loan B Facility

Borrowings under the Term Loan B Facility were comprised of two tranches: a tranche consisting of $575.0 million in aggregate principal amount of term loans maturing on March 24, 2020 (the “Five-Year Term Loans”) and a tranche consisting of a $485.0 million in aggregate principal amount of term loans maturing on March 24, 2022 (the “Seven-Year Term Loans”). The Company was required to make quarterly amortization payments in an amount equal to 1.0%, with the remaining

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

balance payable on the applicable maturity date. As of December 31, 2016, the Company had borrowings outstanding under the Five-Year Term Loans and the Seven-Year Term Loans of $569.3 million and $480.2 million, respectively.

Five-Year Term Loans outstanding under the Term Loan B Facility bore interest based on, at the option of the Company, (i) LIBOR subject to a floor of 1.0%, plus a margin of 5.5%, or (ii) an alternative base rate, plus a margin of 4.5%. Seven-Year Term Loans outstanding under the Term Loan B Facility bore interest based on, at the option of the Company, (i) LIBOR subject to a floor of 1.0%, plus a margin of 6.25%, or (ii) an alternative base rate, plus a margin of 5.25%.

The alternative base rate was equal to the highest of (i) the administrative agent’s prime rate, (ii) the Federal Funds Effective Rate plus 0.5%, or (iii) LIBOR plus 1.0%.

On July 20, 2016, the Debtors filed the Bankruptcy Petitions which constituted an event of default under the Original Credit Agreement and accelerated the Term Loan B Facility indebtedness to become immediately due and payable; however, any efforts to enforce such payment obligations were automatically stayed as a result of the Chapter 11 Proceeding. On the Plan Effective Date, pursuant to the Restructuring Support Agreement entered into on July 8, 2016, holders of the Term Loan B Facility debt received their pro rata share of 100.0% of the New Equity in the Successor, subject to dilution from the issuance of New Equity on account of the Management Incentive Plan, the Rights Offering, the Backstop Fee and the New Warrants as discussed further in Note 2 - Chapter 11 Proceeding and Emergence.

Capital Lease Obligations

In October 2016, the Company entered into amended lease agreements related to the Company’s corporate headquarters and its R&T facility, both originally entered into during 2013 and accounted for as capital leases. The Company determined that both amended lease agreements qualify as a new operating lease under ASC 840 - Leases, which resulted in accounting for the amended leases as a sale-leaseback pursuant to the requirements of ASC 840. The conversion from capital lease to operating lease accounting treatment resulted in the deferral of $6.3 million of gain. As a result of the adoption of Fresh Start Accounting, the Company accelerated the recognition of the deferred gain balance through the Fresh Start adjustments. As of December 31, 2017, the Company had no capital lease obligations.

Interest Expense

As of June 30, 2016, based on the negotiations between the Company and the lenders, it became evident that the restructuring of the Company's capital structure would not include a restructuring of the Company's Revolving Credit Facility, the Five-Year Term Loans and the Seven-Year Term Loans, and these debt obligations, as demand obligations, would not be paid in the ordinary course of business over the term of these loans. As a result, during the second quarter of 2016, the Company accelerated the amortization of the associated original issue discount and deferred financing costs, fully amortizing these amounts as of June 30, 2016. In addition, the Company did not accrue interest that it believed was not probable of being treated as an allowed claim in the Chapter 11 Proceeding. For the year ended December 31, 2016, the Company did not accrue interest totaling $60.5 million under the Credit Agreement subsequent to the Petition Date. For the years ended December 31, 2017 and 2016, interest expense consisted of the following (in thousands):

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Successor			Predecessor
	Years Ended December 31,
	2017			2016

Amended Credit Facility	$	1,779		$	—
DIP Facility	—			2,087
Original Credit Agreement	—			53,596
Capital leases	471			1,206
Accretion of original issue discount	—			4,193
Amortization of deferred financing costs	608			4,590
Original issue discount accelerated amortization	—			48,221
Deferred financing costs accelerated amortization	—			43,720
Interest income and other	(1,331		)	(148		)
Interest expense, net	$	1,527		$	157,465

Note 5 - Goodwill and Other Intangible Assets

On November 30, 2017, the Company acquired all of the outstanding equity interests of O-Tex Holdings, Inc., and its operating subsidiaries ("O-Tex"). See Note 12 - Mergers and Acquisitions for further discussion on the O-Tex transaction. As of December 31, 2017, all off the goodwill reported in the Company's consolidated balance sheet is related to the O-Tex acquisition.

During the first quarter of 2016, utilization and commodity price levels continued to fall towards unprecedented levels and the resulting negative impact on the Company’s results of operations, coupled with the sustained decrease in the Company’s stock price, were deemed triggering events that led to an interim period test for goodwill impairment. The Company chose to bypass a qualitative approach and instead opted to employ the detailed Step 1 impairment testing methodologies discussed below.

Income approach

The income approach impairment testing methodology is based on a discounted cash flow model, which utilizes present values of cash flows to estimate fair value. For the Completion Services and Well Support Services reporting units, the future cash flows were projected based on estimates of projected revenue growth, fleet and rig count, utilization, gross profit rates, SG&A rates, working capital fluctuations, and capital expenditures. For the Other Services reporting unit, the future cash flows were projected based primarily on estimates of future demand for manufactured and refurbished equipment as well as parts and service, gross profit rates, SG&A rates, working capital fluctuations, and capital expenditures. Forecasted cash flows for the three reporting units took into account known market conditions as of March 31, 2016, and management’s anticipated business outlook, both of which had been impacted by the sustained decline in commodity prices.

A terminal period was used to reflect an estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 2.5% for all three reporting units, including an estimated inflation factor.

The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital (“WACC”) of 14.5% for Completion Services, 14.0% for Well Support Services, and 16.0% for Other Services reporting units. These assumptions were derived from unobservable inputs and reflect management’s judgments and assumptions.

Market approach

The market approach impairment testing methodology is based upon the guideline public company method. The application of the guideline public company method was based upon selected public companies operating within the same industry as the Company. Based on this set of comparable competitor data, price-to-earnings multiples were derived and a range of price-to-earnings multiples was determined for each reporting unit. Selected market multiples were 10.6x for Completion Services, 10.5x for Well Support Services and 11.0x for Other Services reporting units.

The fair value determined under the market approach is sensitive to these market multiples, and a decline in any of

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the multiples could reduce the estimated fair value of any of the three reporting units below their respective carrying values. Earnings estimates were derived from unobservable inputs that require significant estimates, judgments and assumptions as described in the income approach.

The estimated fair value determined under the income approach was consistent with the estimated fair value determined under the market approach. The concluded fair value for the Completion Services and Well Support Services reporting units consisted of a weighted average, with an 80.0% weight under the income approach and a 20.0% weight under the market approach. The concluded fair value for the Other Services reporting unit consisted of a weighted average with a 50.0% weight under the income approach and a 50.0% weight under the market approach.

The results of the Step 1 impairment testing indicated potential impairment in the Well Support Services reporting unit. The goodwill associated with both the Completion Services and Other Services reporting units was completely impaired during the third quarter of 2015. As a way to validate the estimated reporting unit fair values, the total market capitalization of the Company was compared to the total estimated fair value of all reporting units, and an implied control premium was derived. Market data in support of the implied control premium was used in this reconciliation to corroborate the estimated reporting unit fair values.

Step 2 of the goodwill impairment testing for the Well Support Services reporting units was performed during the first quarter of 2016, and the results concluded that there was no value remaining to be allocated to the goodwill associated with this reporting unit. As a result, the Company recognized impairment expense of $314.3 million during 2016.

As of December 31, 2016, there was no goodwill remaining to be allocated across the Company's three reporting units. The changes in the carrying amount of goodwill for the years ended December 31, 2017 and 2016 are as follows (in thousands):



	Completion Services			Well Support Services			Total
As of December 31, 2015 (Predecessor)	$	—		$	307,677		$	307,677
Measurement period adjustments	8			5,382			5,390
Impairment expense	(8		)	(314,293		)	(314,301		)
Foreign currency translation and other adjustments	—			1,234			1,234
As of December 31, 2016 (Predecessor)	—			—			—
O-Tex acquisition	147,515			—			147,515
As of December 31, 2017 (Successor)	$	147,515		$	—		$	147,515

Indefinite-Lived Intangible Assets

As of December 31, 2016, the Company had approximately $6.0 million of intangible assets with indefinite useful lives, which were subject to annual impairment tests or more frequently if events or circumstances indicate the carrying amount may not be recoverable.

The Company’s intangible assets associated with intellectual property, research and development (“IPR&D”) consist of technology that is still in the testing phase; however, given the continued market downturn management has made the decision to postpone these projects. Based on the Company's evaluation, it was determined that the IPR&D carry value of $6.0 million was impaired and written down to zero as of December 31, 2016.

As of December 31, 2017, the Company has not acquired additional indefinite-lived intangible assets, and the IPR&D intangible assets remain at zero.

Definite-Lived Intangible Assets

The Company reviews definite-lived intangible assets, along with PP&E, for impairment when a triggering event indicates that the asset may have a net book value in excess of recoverable value. During 2016, management determined the sustained low commodity price levels coupled with the sustained decrease in the Company’s share price were deemed triggering events that provided indicators that its definite-lived intangible assets may be impaired. The Company performed a

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

recoverability test on all of its definite-lived intangible assets and PP&E by comparing the estimated future net undiscounted cash flows expected to be generated from the use of these assets to the carrying amounts 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.

Recoverability testing through June 30, 2016 resulted in the determination that certain intangible assets associated with the Company’s wireline and artificial lift lines of business were not recoverable. The fair value of the wireline and artificial lift assets was determined to be approximately $38.2 million and zero, respectively, resulting in impairment expense of $50.4 million and $4.6 million, respectively. For the year ended December 31, 2016, the Company recorded $55.0 million of impairment expense, as the intangible assets assessed were determined not to be recoverable. For the year ended December 31, 2015, recoverability testing resulted in $11.2 million of impairment expense as the intangible assets assessed were determined not to be recoverable.

The changes in the carrying amounts of other intangible assets for the year ended December 31, 2017 are as follows (in thousands):



	Predecessor							Successor
	Amortization Period	December 31, 2016			Fresh Start Adjustments			On January 1, 2017		Acquisition / (Divestiture)			Amortization Expense			December 31, 2017
Customer relationships	8-15 years	$	80,826		$	(80,826	)	$	—	$	58,100		$	—		$	58,100
Trade name	10-15 years	29,994			26,506			56,500		11,800			—			68,300
Developed technology	5-15 years	21,516			(17,616		)	3,900		(3,900		)	—			—
Non-compete	4-5 years	2,600			(2,600		)	—		1,600			—			1,600
Patents	10 years	35			(35		)	—		—			—			—
		134,971			(74,571		)	60,400		67,600			—			128,000
Less: accumulated amortization		(58,914		)	58,914			—		—			(4,163		)	(4,163		)
Intangible assets, net		$	76,057		$	(15,657	)	$	60,400	$	67,600		$	(4,163	)	$	123,837

Amortization expense for the years ended December 31, 2017, 2016 and 2015 totaled $4.2 million, $10.8 million and $14.5 million, respectively.

Estimated amortization expense for each of the next five years and thereafter is as follows (in thousands):



Years Ending December 31,
2018	$	8,747
2019	8,747
2020	8,747
2021	8,747
2022	8,720
Thereafter	80,129
	$	123,837

Note 6 - Income Taxes

On December 22, 2017, the Tax Cuts and Jobs Act ("U.S. Tax Reform") was enacted by the U.S. federal government. The legislation significantly changed U.S. income tax law, by among other things, lowering the federal corporate income tax rate from 35% to 21%, effective January 1, 2018, implementing a territorial tax system and imposing a one-time toll charge on deemed repatriated earnings of foreign subsidiaries. In addition, there are many new provisions, including changes to expensing of qualified tangible property, the deductions for executive compensation and interest expense, a global intangible low-tax income provision, the base erosion anti-abuse tax, and a deduction for foreign-derived intangible income. The Company's consolidated financial statements for the year ended December 31, 2017 were impacted by the corporate income tax

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

rate reduction going from 35% to 21%. This rate reduction required the revaluation of the Company's deferred tax assets and liabilities as of the U.S. Tax Reform enactment date. The revaluation reflects an assumption that the new federal corporate income tax rate will remain in place for the years in which temporary differences are expected to reverse. The Company estimates that the reduction in the federal tax rate applicable to deferred tax balances will reduce the net deferred tax asset balance, before valuation allowance, by approximately $160.0 million, with a corresponding reduction in the recorded valuation allowance by approximately $162.3 million. As a result of the change in the federal income tax rate, the Company recorded an income tax benefit of approximately $2.3 million during the fourth quarter of 2017.

On December 22, 2017, the SEC issued Staff Accounting Bulletin No. 118 ("SAB 118"). SAB 118 provides the registrant with up to a one year period to finalize the accounting for the impacts of U.S. Tax Reform. During the one year period in which the initial accounting for U.S. Tax Reform impacts is incomplete, a registrant may include a provisional amount when reasonable estimates can be made or continue to apply the prior tax law if a reasonable estimate cannot be made. As discussed above, the Company has estimated the provisional tax impacts related to the corporate income tax rate reduction and the impact on its deferred tax assets and liabilities, after corresponding adjustments to the reported valuation allowance. The deferred tax assets and liabilities table below includes the adjustments from the revaluation of deferred tax balances to reflect the rate reduction for the year ended December 31, 2017. Before U.S. Tax Reform adjustments, the ending net deferred tax liability would have been $6.2 million compared to the reflected ending net deferred tax liability of $3.9 million as of December 31, 2017. The ultimate impact of remeasuring the deferred tax assets and liabilities may differ from the provisional amounts due to gathering additional information to more precisely compute the amount of tax, changes in interpretations and assumptions, additional regulatory guidance that may be issued, and actions the Company may take. The Company expects to finalize accounting for the impacts of U.S. Tax Reform when the 2017 U.S. corporate income tax return is filed in 2018.

The provision for income taxes consisted of the following (in thousands):



	Successor			Predecessor
	Year Ended December 31,			On January 1,			Years Ended December 31,
	2017			2017			2016			2015
Current provision:
Federal	$	(8,475	)	$	—		$	2,047		$	(23,784	)
State	(162		)	—			(1,588		)	(2,265		)
Foreign	121			—			64			100
Total current provision	(8,516		)	—			523			(25,949		)
Deferred (benefit) provision:
Federal	(28,950		)	(4,613		)	(122,302		)	(248,279		)
State	(2,294		)	—			(8,864		)	(20,553		)
Foreign	—			—			1,633			(4,312		)
Total deferred provision	(31,244		)	(4,613		)	(129,533		)	(273,144		)
Provision for income taxes	$	(39,760	)	$	(4,613	)	$	(129,010	)	$	(299,093	)

The following table reconciles the statutory tax rates to the Company’s effective tax rate:

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Successor		Predecessor
	Years Ended December 31,
	2017		2016		2015
Federal statutory rate	35.0	%	35.0	%	35.0	%
State taxes, net of federal benefit	8.0	%	0.3	%	1.4	%
Domestic production activities deduction	—	%	—	%	(0.2	)%
Effect of foreign losses	9.8	%	(2.0	)%	(0.3	)%
Impairment	—	%	(8.8	)%	(9.8	)%
Changes in uncertain tax positions	37.7	%	(0.6	)%	—	%
Effects of the plan of reorganization	1,114.9	%	(1.3	)%	—	%
Valuation allowance	(959.3	)%	(10.9	)%	—	%
Other	(16.3	)%	0.3	%	(0.6	)%
Effective income tax rate	229.8	%	12.0	%	25.5	%

The Company’s deferred tax assets and liabilities consisted of the following (in thousands):



	Successor			Predecessor
	As of December 31,
	2017			2016
Deferred tax assets:
Accrued liabilities	$	2,100		$	25,470
Allowance for doubtful accounts	1,791			2,630
Stock-based compensation	2,570			11,530
Inventory reserve	1,883			9,131
Net operating losses	276,239			231,360
163j interest limitation	41,342			58,426
Amortization of goodwill and intangible assets	4,101			4,526
Other	4,379			3,774
Total deferred tax assets	334,405			346,847
Deferred tax liabilities:
Prepaid assets	(4,438		)	(2,123		)
Depreciation on property, plant and equipment	(37,784		)	(179,428		)
Other	(643		)	(3,873		)
Total deferred tax liabilities	(42,865		)	(185,424		)
Valuation allowances	(295,457		)	(171,016		)
Net deferred tax liability	$	(3,917	)	$	(9,593	)

The Company has approximately $1.1 billion of U.S. federal net operating loss carryforwards (“NOLs”) which, if not utilized, will begin to expire in the year 2035 and state NOLs of approximately $602.4 million which, if not utilized, will expire in various years between 2020 and 2037. Additionally, the Company has approximately $19.9 million of NOLs in other jurisdictions which, if not utilized, will expire in various years between 2020 and 2037. As of December 31, 2017, the Company has recorded a deferred tax asset of approximately $276.2 million relating to NOLs, and an offsetting valuation allowance has been provided for these NOLs due to uncertainty regarding the ultimate realization of the deferred tax assets associated with the NOL carryforwards prior to expiration. Additionally, the Company has foreign operating loss carryforwards of approximately $908.6 million for which the realization of a tax benefit is considered remote. Due to the remote likelihood of utilizing these NOLs, neither the deferred tax asset nor the offsetting valuation allowance has been recorded, and neither is presented in the table above.

The Company's ability to utilize its U.S. 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 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 the Company's stock have aggregate increases in their ownership of such stock of

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

more than 50 percentage points over such stockholders’ lowest ownership percentage during the testing period (generally a rolling three year period). The Company believes it experienced an ownership change in January 2017 as a result of the implementation of the Restructuring Plan and a subsequent ownership change also occurred on or about June 30, 2017. As a result, the Company's pre-change NOLs are subject to limitation under Section 382 of the Code. 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. The Company does not believe either ownership change created a restriction, which, by itself, could cause its pre-change NOLs to expire unused. As of December 31, 2017, management’s assessment that a full valuation allowance is appropriate due to uncertainty about ultimate realization of the deferred tax assets was determined before consideration of a Section 382 limitation. Similar rules and limitations may apply for state income tax purposes. The Company remains subject to ongoing testing for future ownership changes based on shareholder ownership that may create a more restrictive Section 382 limitation on the NOLs in subsequent reporting periods.

The Company’s U.S. federal income tax returns for the tax years 2014 through 2016 remain open to examination by the Internal Revenue Service under the applicable U.S. federal statute of limitations provisions. The various states in which the Company is subject to income tax are generally open to examination for the tax years after 2013.

A reconciliation of unrecognized tax benefit balances is as follows (in thousands):



	Successor			Predecessor
	Years Ended December 31,
	2017			2016
Balance at beginning of year	$	6,525		$	—
Additions based on tax positions related to the current year	—			6,525
Reductions for tax positions of prior years	(6,525		)	—
Balance at end of year	$	—		$	6,525

As of December 31, 2017, the Company had no balances related to unrecognized tax benefits and associated interest and penalties.

The Company classifies interest and penalties within the provision for income taxes. The Company had no interest and penalties in the provision for income taxes for each of the years ended December 31, 2017, 2016 and 2015.

Note 7 - Share-Based Compensation

Successor Equity Plans

Pursuant to the Restructuring Plan, the Company adopted the C&J Energy Services, Inc. 2017 Management Incentive Plan (as amended from time to time, the "MIP") as of the Plan Effective Date.

The MIP provides for the grant of share-based awards to the Company’s employees, consultants and non-employee directors. The following types of awards are available for issuance under the MIP: incentive stock options and nonqualified stock options, share appreciation rights, restricted shares, restricted share units, dividend equivalent rights, performance awards, share awards, other share-based awards and substitute awards. As of December 31, 2017, only nonqualified stock options, restricted shares and performance awards have been awarded under the MIP.

A total of approximately 8.0 million shares of common stock were originally authorized and approved for issuance under the MIP. The number of shares of common stock available for issuance under the MIP is subject to adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, share dividend, share split or reverse share split, cash dividend, property dividend, combination or exchange of shares, repurchase of shares, change in corporate structure or any similar corporate event or transaction. The number of shares of common stock available for issuance may also increase due to the termination of an award granted under the MIP or by expiration, forfeiture, cancellation or otherwise without the issuance of the common stock.

Stock Options

The fair value of each option award granted under the MIP is estimated on the date of grant using the Black-Scholes option-pricing model. Determination of the fair value was a matter of judgment and often involved the use of significant estimates and assumptions. Additionally, due to the Company’s lack of historical volume of option activity, the expected term of options granted was derived using the “plain vanilla” method. Expected volatilities were based on comparable

100

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

public company data, with consideration given to the Company’s limited historical data. The Company makes estimates with respect to employee termination and forfeiture rates of the options within the valuation model. The risk-free rate is based on the approximate U.S. Treasury yield rate in effect at the time of grant. During the year ended December 31, 2017, approximately 0.4 million nonqualified stock options were granted under the MIP to certain of the Company's executive officers at a fair market value ranging from $16.55 to $22.19 per nonqualified stock option. Stock options granted during the first quarter of 2017 will expire on the tenth anniversary of the grant date and will vest over three years of continuous service from the grant date, with 34% vesting immediately upon the grant date, and 22% on each of the first, second and third anniversaries of the grant date. Stock options granted during the fourth quarter of 2017 will expire on the tenth anniversary of the grant date and will vest over three years of continuous service from the grant date, with one-third vesting on each of the first, second and third anniversaries of the grant date.

The following table presents the assumptions used in determining the fair value of option awards granted during the year ended December 31, 2017.



		Year Ended December 31,
		2017
Expected volatility		50.1% - 53.2%
Expected dividends		None
Exercise price		$30.83 - $42.65
Expected term (in years)		5.7 - 6.0
Risk-free rate		2.03% - 2.24%

The weighted average grant date fair value of options granted during the year ended December 31, 2017 was $20.66.

A summary of the Company’s stock option activity for the year ended December 31, 2017 is presented below.



	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
	(in thousands)				(in years)	(in thousands)
Outstanding at December 31, 2016 (Predecessor)	4,416		$	13.18	3.86	$	—
Canceled	(4,416	)	13.18		3.86	—
Outstanding at January 1, 2017 (Successor)	—		$	—	—	$	—
Granted	351		39.43		—	—
Exercised	—		—		—	—
Forfeited	—		—		—	—
Outstanding at December 31, 2017 (Successor)	351		$	39.43	9.34	$	253
Exercisable at December 31, 2017 (Successor)	87		$	42.65	9.10	$	—

As of December 31, 2017, the Company had approximately $4.2 million in unrecognized compensation cost related to outstanding stock options to be expensed over a weighted average remaining service period of 2.4 years.

Restricted Stock

The value of the Company’s outstanding restricted stock is based on the closing price of the Company’s common stock on the NYSE on the date of grant. During year ended December 31, 2017, approximately 1.7 million shares of restricted stock were granted to employees and non-employee directors under the MIP, at fair market values ranging from $31.52 to $44.90 per share of restricted stock. Restricted stock awards granted to employees during the first quarter of 2017 will vest over three years of continuous service from the grant date, with 34% having vested immediately upon the grant date, and 22% on each of the first, second and third anniversaries of the grant date. Restricted stock awards granted to non-employee directors will vest in full on the first anniversary of the date of grant, subject to each director's continued service. Restricted stock

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

awards granted to employees during the fourth quarter of 2017 will vest over three years of continuous service from the grant date, with one-third vesting on each of the first, second and third anniversaries.

To the extent permitted by law, the recipient of an award of restricted stock will generally have all of the rights of a stockholder with respect to the underlying common stock, including the right to vote the common stock and to receive all dividends or other distributions made with respect to the common stock. Dividends on restricted stock will be deferred until the lapsing of the restrictions imposed on the stock and will be held by the Company for the account of the recipient (either in cash or to be reinvested in restricted stock) until such time. Payment of the deferred dividends and accrued interest, if any, shall be made upon the lapsing of restrictions on the restricted stock, and any dividends deferred in respect of any restricted stock shall be forfeited upon the forfeiture of such restricted stock. As of December 31, 2017, the Company had not issued any dividends.

A summary of the status and changes during the year ended December 31, 2017 of the Company’s shares of non-vested restricted shares is presented below:



	Shares		Weighted Average Grant-Date Fair Value
	(in thousands)
Non-vested at December 31, 2016 (Predecessor)	898		$	15.34
Canceled	(898	)	(15.34		)
Non-vested at January 1, 2017 (Successor)	—		$	—
Granted	1,664		37.92
Forfeited	(38	)	43.00
Vested	(288	)	43.83
Non-vested at December 31, 2017 (Successor)	1,338		$	36.51

As of December 31, 2017, the Company had approximately $38.9 million in unrecognized compensation cost related to restricted stock to be expensed over a weighted average remaining service period of 2.6 years.

Performance Stock

During the fourth quarter of 2017, the Company granted approximately 0.1 million shares of performance stock under the MIP to certain of the Company's executive officers at a fair market value of approximately $37.20 per share of restricted stock. The performance award cliff vests at the end of a three year performance period, and the participants may earn between 0% and 200% of the target number of the shares granted based on actual stock price performance upon comparison to a peer group. The vesting of these awards is subject to the employee's continued employment. The Company values equity awards with market conditions at the grant date using a Monte Carlo simulation model which simulates many possible future outcomes.

The following table presents the assumptions used in determining the fair value of the performance stock granted during the fourth quarter of 2017.



		Year Ended December 31,
		2017
Expected volatility, including peer group		30.8% - 81.6%
Expected dividends		None
30 calendar day volume weighted average stock price, including peer group		$2.13 - $133.20
Expected term (in years)		3.0
Risk-free rate		1.94% - 1.95%

A summary of the status and changes during the year ended December 31, 2017 of the Company’s performance stock is presented below:

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Shares	Weighted Average Grant-Date Fair Value
	(in thousands)
Non-vested at December 31, 2017 (Predecessor)	—	$	—
Granted	92	37.20
Forfeited	—	—
Vested	—	—
Non-vested at December 31, 2017 (Successor)	92	$	37.20

As of December 31, 2017, the Company had approximately $3.4 million in unrecognized compensation cost related to performance stock to be expensed over a weighted average remaining service period of 3.0 years.

Share-based compensation expense was $23.4 million for the year ended December 31, 2017, and is included in selling, general and administrative expenses, direct costs and research and development on the consolidated statements of operations. Due to the valuation allowance that has been provided for NOLs as a result of the uncertainty regarding the ultimate realization of the Company's deferred tax assets, there was no income tax benefit recognized in the consolidated statements of operations in connection with share-based compensation expense for the year ended December 31, 2017.

Predecessor Equity Plans

In connection with the Nabors Merger, the Company approved and adopted the C&J Energy Services 2015 Long Term Incentive Plan (the “2015 LTIP”), effective as of March 23, 2015, contingent upon the consummation of the Nabors Merger. The 2015 LTIP served as an assumption of the Old C&J 2012 Long-Term Incentive Plan, (the “2012 LTIP”), with certain non-material revisions made and no increase in the number of shares remaining available for issuance under the 2012 LTIP. Prior to the adoption of the 2015 LTIP, all share-based awards granted to Old C&J employees, consultants and non-employee directors were granted under the 2012 LTIP and, following the 2015 LTIP’s adoption, no further awards were granted under the 2012 LTIP. Awards that were previously outstanding under the 2012 LTIP would have continued to remain outstanding under the 2015 LTIP, as adjusted to reflect the Nabors Merger. At the closing of the Nabors Merger, restricted shares and stock option awards were granted under the 2015 LTIP to certain employees of the C&P Business and approximately 0.4 million C&J common shares underlying those awards were deemed part of the consideration paid to Nabors for the Nabors Merger.

The 2015 LTIP provided for the grant of share-based awards to the Company’s employees, consultants and non-employee directors. The following types of awards were available for issuance under the 2015 LTIP: incentive stock options and nonqualified stock options, share appreciation rights, restricted shares, restricted share units, dividend equivalent rights, performance awards and share awards. As of December 31, 2016, only nonqualified stock options and restricted shares were awarded under the 2015 LTIP and 2012 LTIP. No grants were issued during the year ended December 31, 2016.

Approximately 11.3 million shares were available for issuance under the 2015 LTIP as of December 31, 2016. The number of common shares available for issuance under the 2015 LTIP was subject to adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, share dividend, share split or reverse share split, cash dividend, property dividend, combination or exchange of shares, repurchase of shares, change in corporate structure or any similar corporate event or transaction.

A total of 4.3 million common shares were originally authorized and approved for issuance under the 2012 LTIP and on June 4, 2015, the shareholders of the Company approved the First Amendment to the 2015 LTIP, which increased the number of common shares that may be issued under the 2015 LTIP by approximately 3.6 million shares. The shareholders of the Company approved the Second Amendment to the 2015 LTIP in February 2016, which increased the number of common shares that may be issued by approximately 6.0 million shares. Including the add-back of approximately 0.9 million restricted shares and 0.7 million options canceled or expired under the 2012 LTIP and 2015 LTIP during 2016, approximately 11.3 million shares were available for issuance under the 2015 LTIP as of December 31, 2016. The number of common shares available for issuance under the 2015 LTIP was subject to adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, share dividend, share split or reverse share split, cash dividend, property dividend, combination or exchange of shares, repurchase of shares, change in corporate structure or any similar corporate event or transaction. The number of common shares available for issuance were also subject to increase due to the termination of an award granted under the 2015 LTIP, the 2012 LTIP or the Prior Plans (as defined

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

below), by expiration, forfeiture, cancellation or otherwise without the issuance of the common shares. The 2015 LTIP was terminated as described in Note 2 - Chapter 11 Proceeding and Emergence, pursuant to the Restructuring Plan, the liquidation of C&J Energy Services Ltd. was completed under the laws of Bermuda, and all of the existing shares of the Predecessor's common equity were canceled as of the Effective Date. Also, on the Effective Date, the Successor issued the New Warrants to the holders of the canceled Predecessor common shares, provided that such class of holders voted to accept the Restructuring Plan.

Stock Options

The fair value of each option award granted under the 2015 LTIP, the 2012 LTIP and the Prior Plans was estimated on the date of grant using the Black-Scholes option-pricing model. Option awards were generally granted with an exercise price equal to the market price of the Company’s common shares on the grant date. Due to the Company’s lack of historical volume of option activity, the expected term of options granted was derived using the “plain vanilla” method. In addition, expected volatilities were based on comparable public company data, with consideration given to the Company’s limited historical data. The Company made estimates with respect to employee termination and forfeiture rates of the options within the valuation model. The risk-free rate was based on the approximate U.S. Treasury yield rate in effect at the time of grant. No options were granted during the year ended December 31, 2016.

The following table presents the assumptions used in determining the fair value of option awards during the year ended December 31, 2015. No stock options were granted by the Company for the year ended December 31, 2016.



		Year Ended December 31,
		2015
Expected volatility		52.3%
Expected dividends		None
Exercise price		$7.93 - $27.12
Expected term (in years)		0.3 - 4.3
Risk-free rate		0.03% - 1.3%

The weighted average grant date fair value of options granted during the year ended December 31, 2015, was $4.74.

A summary of the Company’s stock option activity through December 31, 2016 is presented below.



	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
	(in thousands)				(in years)	(in thousands)
Outstanding at December 31, 2014 (Predecessor)	5,067		$	11.70	5.40	$	21,395
Granted	267		10.49		—	—
Exercised	(154	)	2.94		—	—
Forfeited	(61	)	19.03		—	—
Outstanding at December 31, 2015 (Predecessor)	5,119		$	11.82	4.41	$	2,874
Granted	—		—		—	—
Exercised	—		—		—	—
Forfeited	(703	)	3.19		—	—
Outstanding at December 31, 2016 (Predecessor)	4,416		$	13.18	3.86	$	—

The total intrinsic value of options exercised during the year ended December 31, 2015 was $0.6 million.

Restricted Shares

Historically, restricted shares were valued based on the closing price of the Company’s common shares on the NYSE on the date of grant. During the year ended December 31, 2016 there were no restricted shares granted to employees

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and non-employee directors under the 2015 LTIP. During the year ended December 31, 2015 approximately 2.8 million restricted shares were granted to employees and non-employee directors under the 2015 LTIP, including approximately 0.6 million replacement restricted shares, at fair market values ranging from $3.55 to $15.10 per share.

To the extent permitted by law, the recipient of an award of restricted shares had all of the rights of a shareholder with respect to the underlying common shares, including the right to vote the common shares and to receive all dividends or other distributions made with respect to the common shares. Dividends on restricted shares would have been deferred until the lapsing of the restrictions imposed on the shares and would be held by the Company for the account of the recipient (either in cash or to be reinvested in restricted shares) until such time. Payment of the deferred dividends and accrued interest, if any, would have been made upon the lapsing of restrictions on the restricted shares, and any dividends deferred in respect of any restricted shares would be forfeited upon the forfeiture of such restricted shares. As of December 31, 2016, the Company did not issue any dividends

A summary of the status and changes during the year ended December 31, 2016 of the Company’s shares of non-vested restricted shares is presented below:



	Shares		Weighted Average Grant-Date Fair Value
	(in thousands)
Non-vested at December 31, 2014 (Predecessor)	1,377		$	23.39
Granted	2,850		$	13.50
Forfeited	(238	)	$	14.81
Vested	(718	)	$	21.97
Non-vested at December 31, 2015 (Predecessor)	3,271		$	15.70
Granted	—		—
Forfeited	(576	)	15.30
Vested	(1,797	)	15.92
Non-vested at December 31, 2016 (Predecessor)	898		$	15.34

As of December 31, 2016, and 2015 there was $8.9 million and $29.9 million of total unrecognized compensation cost related to restricted shares. That cost was expected to be recognized over a weighted-average period of 1.42 years. The weighted-average grant-date fair value per share of restricted shares granted during the year ended December 31, 2015 was $13.50.

As of December 31, 2016, the Company had 5.3 million stock options and restricted shares outstanding to employees and non-employee directors, 0.3 million of which were issued under the 2006 Plan, 3.9 million were issued under the 2010 Plan, 0.2 million were issued under the 2012 Plan and the remaining 0.9 million were issued under the 2015 Plan.

Share-based compensation expense was $17.7 million and $18.5 million for the years ended December 31, 2016 and 2015, respectively, and is included in selling, general and administrative expenses, direct costs and research and development on the consolidated statements of operations. The total income tax benefit recognized in the consolidated statements of operations in connection with share-based compensation expense was approximately $6.2 million and $6.5 million for the years ended December 31, 2016 and 2015, respectively.

Note 8 - Related Party Transactions

The Company obtained support services from vendors which are affiliated with one of its employees. For the year ended December 31, 2017, purchases from these vendors totaled $0.9 million. Amounts due to these vendors as of December 31, 2017 totaled $0.3 million. There were no purchases from these vendors for the years ended December 31, 2016 or 2015.

The Company obtained support services from Nabors Corporate Services, Inc., on a transitional basis, for the processing of payroll, benefits and certain administrative services of the C&P business in normal course following the completion of the Nabors Merger. There were no obligations incurred to Nabors Corporate Services during 2017. During 2016 and prior to the Confirmation Date, the Company, the Official Committee of Unsecured Creditors of CJ Holding Co, the Steering Committee of Lenders under the Credit Agreement and the DIP Facility, and Nabors entered into a mediated

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settlement agreement that was subsequently approved by the Bankruptcy Court whereby, among other things, Nabors was awarded two allowed proofs of claim totaling $13.3 million. As of December 31, 2016, the allowed proofs of claim were included in liabilities subject to compromise on the consolidated balance sheet. As a result of the Company's emergence from the Chapter 11 Proceeding and the cancellation of the Predecessor common shares, Nabors Corporate Services is no longer considered a related party.

The Company leased certain properties from Nabors, and Nabors leased certain properties from the Company. For the year ended December 31, 2016, the Company incurred obligations to Nabors of approximately $0.6 million under the leases, and Nabors incurred obligations to C&J of approximately $0.5 million and $0.1 million under the leases for each of the years ended December 31, 2017 and 2016. Amounts payable to Nabors at December 31, 2017 were $0.9 million. As a result of the Company's emergence from the Chapter 11 Proceeding and the cancellation of the Predecessor common shares, Nabors Corporate Services is no longer considered a related party.

The Company provided certain services to Shehtah Nabors LP, a Nabors partnership with a third party, pursuant to a Management Agreement and a Cash Flow Sharing Agreement (collectively, “Shehtah Agreements”). Nabors incurred obligations to the Company of approximately $1.8 million under the Shehtah Agreements during 2016. There were no amounts due to the Company under the Shehtah Agreements at December 31, 2016. The Company did not provide services to Shehtah during 2017. As a result of the Company's emergence from the Chapter 11 Proceeding and the cancellation of the Predecessor common shares, Nabors Corporate Services is no longer considered a related party.

The Company utilizes the services of certain saltwater disposal wells owned by Pyote Water Solutions, LLC, Pyote Water Systems, LLC, Pyote Water Systems II, LLC and Pyote Water Systems III, LLC (together “Pyote”) used in the disposal of certain fluids associated with oil and gas production. A former member of the Company's Board of Directors, who served from March 24, 2015 until December 16, 2016, holds the position of President and Chief Manager of Pyote and serves as Chairman of the Board of Governors of Pyote. Amounts invoiced from Pyote totaled approximately $0.8 million and $0.6 million for the years ended December 31, 2016 and 2015, respectively. Amounts payable to this vendor at December 31, 2016 were less than $0.1 million. In addition, the Company provides certain workover rig services, fluid hauling services and plug and abandonment services to Pyote. Revenues from Pyote totaled approximately $0.3 million for the year ended December 31, 2015, and no services were provided to Pyote during 2016. There were no amounts due to the Company from Pyote at December 31, 2016. For the year ended December 31, 2017, Pyote was no longer a related party.

The Company purchased certain of its equipment from vendors affiliated with a former member of its Board of Directors. For the year ended December 31, 2015, purchases from these vendors totaled $1.9 million. Amounts payable to these vendors at December 31, 2015 were less than $0.1 million. There were no purchases from these vendors for the years ended December 31, 2017 or 2016. For the year ended December 31, 2017, the vendors were no longer considered related parties.

The Company obtains office space, equipment rentals, tool repair services and other supplies from vendors affiliated with several employees. For the years ended December 31, 2017, 2016 and 2015, purchases from these vendors totaled $0.5 million in each year. Amounts payable to these vendors at December 31, 2016 were less than $0.1 million. There were no amounts due to these vendors as of December 31, 2017.

The Company has an unconsolidated equity method investment with a vendor that provided the Company with raw material for its discontinued specialty chemical business. For the years ended December 31, 2016 and 2015, purchases from this vendor were $1.7 million and $11.8 million, respectively. There were no purchases from this vendor for the year ended December 31, 2017. Amounts payable to this vendor at December 31, 2016 and 2015 were $2.1 million and $1.5 million, respectively. There were no amounts payable to this vendor as of December 31, 2017.

The Company obtained drilling fluids from a vendor which was affiliated with one of its former employees. For the year ended December 31, 2015, purchases from this vendor totaled $2.1 million. Amounts due to this vendor at December 31, 2015 were $0.2 million. There were no purchases from this vendor for the year ended December 31, 2016. For the year ended December 31, 2017, this vendor was no longer considered a related party.

Note 9 - Business Concentrations

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. Concentrations of credit risk with respect to accounts receivable are limited because the Company performs credit evaluations, sets credit limits, and monitors the payment patterns of its customers. Cash

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balances on deposits with financial institutions, at times, may exceed federally insured limits. The Company regularly monitors the institutions’ financial condition.

The Company’s top ten customers accounted for approximately 40.7%, 46.0% and 53.6% of the Company’s consolidated revenue for the years ended December 31, 2017, 2016 and 2015, respectively. For the year ended December 31, 2017 and December 31, 2016, no individual customer accounted for 10.0% or more of the Company's consolidated revenue. For the year ended December 31, 2015 revenue from one customer individually represented 15.5% of the Company’s consolidated revenue. Other than the customer noted above, no other customer accounted for 10.0% or more of the Company’s consolidated revenue in 2015. Revenue was earned from this customer within the Company’s Completion Services and Well Support Services segments.

Note 10 - Commitments and Contingencies

Environmental

The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for the protection of the environment. The Company continues to monitor the status of these laws and regulations. However, the Company cannot predict the future impact of such standards and requirements on its business, which are subject to change and can have retroactive effectiveness.

Currently, the Company has not been fined, cited or notified of any environmental violations or liabilities that would have a material adverse effect upon its consolidated financial position, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred in the near term to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.

Litigation

The Company is, and from time to time may be, involved in claims and litigation arising in the ordinary course of business. Because there are inherent uncertainties in the ultimate outcome of such matters, it is presently not possible to determine the ultimate outcome of any pending or potential claims or litigation against the Company; however, management believes that the outcome of those matters that are presently known to the Company will not have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.

Contingent Consideration Liability

On May 18, 2015, the Company acquired all of the outstanding equity interests of ESP Completion Technologies LLC, a manufacturer of wellheads, artificial lift completion tools and electric submersible pumps for approximately $34.0 million and including a contingent consideration liability valued at approximately $14.4 million at the date of the acquisition. If the acquiree is able to achieve certain levels of EBITDA over a three-year period, the Company will be obligated to make future tiered payments of up to $29.5 million. The contingent consideration liability is remeasured on a fair value basis each quarter until it is paid or expires. As of December 31, 2017, the earn-out was estimated to have zero value.

Service Equipment and Components

The Company has agreed to purchase service equipment and components for $18.4 million as of December 31, 2017. The Company expects to fulfill these commitments during 2018.

Operating Leases

The Company leases certain property and equipment under non-cancelable operating leases. The remaining terms of the operating leases generally range from 1 to 6 years.

Lease expense under all operating leases totaled $10.6 million, $10.0 million and $14.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, the future minimum lease payments under non-cancelable operating leases were as follows (in thousands):

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Years Ending December 31,

2018	$	9,076
2019	5,737
2020	4,719
2021	3,523
2022	3,498
Thereafter	2,487
	$	29,040

Note 11 - Employee Benefit Plans

The Company maintains a contributory profit sharing plan under a 401(k) arrangement which covers all employees meeting certain eligibility requirements. Eligible employees can make annual contributions to the plan up to the maximum amount allowed by current federal regulations, but no more than 80.0% of compensation as noted in the plan document. The Company’s 401(k) contributions for the years ended December 31, 2017 and 2015 totaled $3.3 million and $4.8 million, respectively. Due to the continued market downturn and the Company's Chapter 11 Proceeding during 2016, no 401(k) contributions were made by the Company throughout 2016.

Note 12 - Mergers and Acquisitions

2017

Acquisition of O-Tex

On November 30, 2017, the Company acquired all of the outstanding equity interest of O-Tex for approximately $271.9 million, consisting of cash of approximately $132.5 million and 4.42 million shares of the Company's common stock with a fair value of $138.2 million. The Company also acquired the remaining 49.0% non-controlling interest in an O-Tex subsidiary for $1.25 million.

O-Tex specializes in both primary and secondary downhole specialty cementing services in most major U.S. shale plays. This strategic transaction immediately expands C&J’s cementing business with enhanced capabilities and strengthens the Company’s position as a leading oilfield services provider with a best-in-class well construction, intervention and completions platform.

The O-Tex transaction was accounted for using the acquisition method of accounting for business combinations. In applying the acquisition method of accounting, the Company was required to determine the accounting acquirer which was deemed to be the party possessing the controlling financial interest. The Company determined that C&J possessed the controlling financial interest.

The preliminary purchase price was allocated to the net assets acquired based upon their estimated fair values, as shown below (in thousands). The estimated fair values of certain assets and liabilities, including property plant and equipment, other intangible assets, and contingencies required significant judgments and estimates. As a result, the provisional measurements below are preliminary and subject to change during the measurement period and such changes could be material. Valuations are not complete due to the timing of the acquisition during the second half of the fourth quarter. C&J continues to assess the fair values of the assets acquired and liabilities assumed. All of the goodwill associated with the O-Tex transaction was allocated to the Completion Services reporting unit.

The preliminary purchase price was allocated to the net assets acquired based upon their estimated fair values, as follows (in thousands):

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Current assets	$	45,895
Property and equipment	64,496
Goodwill	147,515
Other intangible assets	71,500
Total assets acquired	$	329,406

Current liabilities	$	17,442
Deferred income taxes	31,301
Other liabilities	8,746
Total liabilities assumed	$	57,489
Net assets acquired	$	271,917

The preliminary fair value and gross contractual amount of accounts receivable acquired on November 30, 2017 was $30.0 million and $30.1 million, respectively. Based on the age of certain accounts receivable, a portion of the gross contractual amount was estimated to be uncollectible.

Property, plant and equipment assets acquired consist of the following preliminary fair values (in thousands) and preliminary ranges of estimated useful lives. As with fair value estimates, the determination of estimated useful lives requires judgments and assumptions that are preliminary and subject to change during the measurement period.



	Estimated Useful Lives	Estimated Fair Value
Land	Indefinite	$	2,010
Building and leasehold improvements	5-25	5,700
Office furniture, fixtures and equipment	3-5	946
Machinery & Equipment	2-10	52,880
Construction in progress		2,960
Property, plant and equipment		$	64,496

Other intangibles were assessed a preliminary fair value of $71.5 million with a preliminary weighted average amortization period of approximately 14.8 years. These intangible assets consist of customer relationships of $58.1 million, amortizable over 15 years, trade name of $11.8 million, amortizable over 15 years, and non-compete agreements of $1.6 million, amortizable over five years. The amount allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. Goodwill was allocated to the Company's Completion Services reporting unit. The goodwill recognized as a result of the O-Tex transaction was primarily attributable to the expected increased economies of scale, enhanced capabilities and resources, and an expanded geographic footprint. The tax deductible portion of goodwill and other intangibles is $4.4 million and $10.7 million, respectively.

The Company treated the O-Tex acquisition as a non-taxable transaction. Such treatment resulted in the acquired assets and liabilities having carryover basis for tax purposes. An estimated deferred tax liability in the amount of $31.3 million was recorded to account for the differences between the preliminary purchase price allocation and carryover tax basis.

Acquisition-related costs associated with the O-Tex transaction were expensed as incurred and totaled $4.4 million for the year ended December 31, 2017, and are included in selling, general and administrative expenses.

The results of operations for O-Tex that have been included in C&J's consolidated financial statements subsequent to the November 30, 2017 acquisition date through December 31, 2017 include revenue of $16.2 million and a net income of $0.4 million. The following unaudited pro forma results of operations have been prepared as though the O-Tex transaction was completed on January 1, 2016. Pro forma amounts are based on the purchase price allocation of the acquisition and are not necessarily indicative of results that may be reported in the future (in thousands):

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	Year Ended December 31, 2017			Year Ended December 31, 2016
Revenues	$	1,797,231		$	1,067,075
Net loss	$	(7,520	)	$	(939,454	)

2015

Merger between Old C&J and the C&P Business of Nabors

On March 24, 2015, Old C&J and Nabors completed the combination of Old C&J with the C&P Business. The resulting combined company was renamed C&J Energy Services Ltd. At the closing of the combination, Nabors received total consideration of $1.4 billion, subject to working capital adjustments, in the form of $688.1 million in cash, $5.5 million in cash to reimburse Nabors for operating assets acquired prior to March 24, 2015, and $714.8 million in C&J common shares. The C&J common share value was based upon Old C&J’s closing stock price on March 23, 2015 and consisted of approximately 62.5 million C&J common shares issued to Nabors and approximately 0.4 million designated C&J common shares attributable to replacement restricted share and share option awards issued to certain employees of the C&P Business for the pre-acquisition-related employee service period. Upon the closing of the combination and as of December 31, 2015, Nabors owned approximately 53.0% of the outstanding and issued common shares of Old C&J, with the remainder held by former Old C&J shareholders.

On September 25, 2015, C&J and Nabors agreed to a working capital adjustment of $43.4 million in favor of C&J, which was accounted for as a reduction to the purchase price of the C&P Business.

The Nabors Merger was accounted for using the acquisition method of accounting for business combinations. In applying the acquisition method of accounting, Old C&J and Nabors were required to determine both the accounting acquirer and the accounting acquiree with the accounting acquirer deemed to be the party possessing the controlling financial interest. Irrespective of Nabors 53.0% common share ownership in C&J immediately following the closing of the Nabors Merger, Old C&J and Nabors determined that Old C&J possessed the controlling financial interest, based on, among other factors, the presence of a majority of Old C&J directors on the C&J board of directors and through the composition of C&J senior management consisting almost entirely of the executive officers of Old C&J. Old C&J and Nabors therefore concluded the business combination should be treated as a reverse acquisition with Old C&J as the accounting acquirer.

C&J financed the cash portion of the Nabors Merger and repaid previously outstanding revolver debt with borrowings drawn under the Original Credit Agreement which provided for senior secured credit facilities in an aggregate principal amount of $1.66 billion. See Note 4 - Debt for further discussion on the Company’s Original Credit Agreement.

The purchase price was allocated to the net assets acquired based upon their estimated fair values, as shown below (in thousands). The estimated fair values of certain assets and liabilities, including accounts receivable, inventory, property plant and equipment, other intangible assets, taxes (including uncertain tax positions), and contingencies required significant judgments and estimates.

All of the goodwill associated with the Nabors Merger was allocated to the Completion Services and Well Support Services reporting units. As part of the Company's interim test for goodwill impairment, during the third quarter of 2015, all of the goodwill allocated to the Completion Services reporting unit was written off. In addition, during the first quarter of 2016, all of the goodwill allocated to the Well Support Services reporting unit was written off. See Note 5 - Goodwill and Other Intangible Assets for further discussion.

The purchase price was initially allocated to the net assets acquired during the first quarter of 2015 and subsequently adjusted during 2015 and in the first quarter of 2016 in connection with the measurement period based upon revised estimated fair values, as follows (in thousands):

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	Amounts Recognized as of Merger Date			Measurement Period Adjustments ⁽¹⁾			Estimated Fair Value
Accounts receivable	$	262,973		$	11,079		$	274,052
Inventory	35,491			(7,372		)	28,119
Other current assets	8,857			(1,940		)	6,917
Property, plant and equipment	1,024,622			(59,378		)	965,244
Goodwill	444,162			12,684			456,846
Other intangible assets	28,300			13,700			42,000
Other assets	11,171			(2,913		)	8,258
Total assets acquired	1,815,576			(34,140		)	1,781,436
Accounts payable	(195,913		)	19,610			(176,303		)
Other current liabilities	(23,813		)	(7,503		)	(31,316		)
Deferred income taxes	(187,515		)	(21,368		)	(208,883		)
Total liabilities assumed	(407,241		)	(9,261		)	(416,502		)
Net assets acquired	$	1,408,335		$	(43,401	)	$	1,364,934

(1) The measurement period adjustments reflect changes in the estimated fair values of certain assets and liabilities, including income taxes. The measurement period adjustments were recorded to reflect new information obtained about facts and circumstances existing as of the date the Nabors Merger was consummated and did not result from intervening events subsequent to that date.

The fair value and gross contractual amount of accounts receivable acquired on March 24, 2015 was $274.1 million and $296.2 million, respectively. Based on the age of certain accounts receivable, a portion of the gross contractual amount was estimated to be uncollectible.

Property, plant and equipment assets acquired consist of the following fair values (in thousands) and ranges of estimated useful lives. As with fair value estimates, the determination of estimated useful lives requires judgments and assumptions.



	Estimated Useful Lives	Estimated Fair Value
Land	Indefinite	$	42,741
Building and leasehold improvements	2-25	79,456
Office furniture, fixtures and equipment	2-5	2,845
Machinery & Equipment	2-10	628,791
Transportation equipment	2-5	166,457
Construction in progress		44,954
Property, plant and equipment		$	965,244

Other intangibles were assessed a fair value of $42.0 million with a weighted average amortization period of approximately 11 years. These intangible assets consist of developed technology of $19.6 million, amortizable over 5 – 15 years, customer relationships of $13.0 million, amortizable over 15 years, trade name of $8.5 million, amortizable over ten years, and non-compete agreements of $0.9 million, amortizable over five years. The amount allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. Goodwill was allocated between C&J’s Completion Services and Well Support Services reporting units on the basis of historical levels of EBITDA with $141.4 million allocated to Completion Services and $315.4 million allocated to Well Support Services. The goodwill recognized as a result of the Nabors Merger was primarily attributable to the expected increased economies of scale, capabilities, resources and geographic footprint of the combined company as well as the cost savings opportunities as C&J expected to capitalize on synergies from the new combined company. The tax deductible portion of goodwill and other intangibles is $60.8 million and $22.3 million, respectively.

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The Company treated the Nabors Merger as a non-taxable transaction. Such treatment resulted in the acquired assets and liabilities having carryover basis for tax purposes. A deferred tax liability in the amount of $208.9 million was recorded to account for the differences between the preliminary purchase price allocation and carryover tax basis.

Acquisition-related costs associated with the Nabors Merger were expensed as incurred and totaled $42.7 million for the year ended December 31, 2015, and are included in selling, general and administrative expenses.

The results of operations for the C&P Business that have been included in C&J's consolidated financial statements from the March 24, 2015 acquisition date through December 31, 2015 include revenue of $822.2 million and a net loss of $211.1 million. The following unaudited pro forma results of operations have been prepared as though the Nabors Merger was completed on January 1, 2014. Pro forma amounts are based on the purchase price allocation of the acquisition and are not necessarily indicative of results that may be reported in the future (in thousands):



	Year Ended December 31, 2015			Year Ended December 31, 2014
Revenues	$	2,114,671		$	3,861,412
Net loss	$	(879,231	)	$	(244,183	)

Acquisition of Artificial Lift Provider

On May 18, 2015, the Company acquired all of the outstanding equity interests of ESP Completion Technologies LLC, a manufacturer of wellheads, artificial lift completion tools and electric submersible pumps ("Artificial Lift Provider") for approximately $34.0 million consisting of cash of approximately $13.6 million, a holdback of $6.0 million, and an earn-out valued at approximately $14.4 million on the acquisition date.

During the second quarter of 2016, C&J and the sellers agreed to a working capital adjustment of $0.5 million in favor of C&J, which was accounted for as a reduction to the purchase price of ESP Completion Technologies LLC. The adjusted purchase price of $33.5 million was allocated to the net assets acquired based upon their estimated fair values, as follows (in thousands):



Current assets	$	5,822
Property, plant and equipment	2,529
Goodwill	24,219
Other intangible assets	5,173
Total assets acquired	37,743
Current liabilities	(1,927		)
Deferred income taxes	(2,067		)
Other liabilities	(276		)
Total liabilities assumed	(4,270		)
Net assets acquired	$	33,473

If Artificial Lift Provider is able to achieve certain levels of EBITDA over a three-year period, the Company will be obligated to make future tiered payments of up to $29.5 million. This could result in a maximum total purchase price of $49.1 million. The potential payment is considered contingent consideration. At the acquisition date, the fair value of this earn-out was determined using a Monte Carlo simulation model over many simulated possible future outcomes which yielded a value of $14.4 million. The earn-out has been remeasured on a fair value basis each quarter and will continue to be remeasured each quarter until the contingent consideration is paid or expires. As of December 31, 2017, the earn-out was estimated to have zero value.

Note 13 - Segment Information

In accordance with ASC No. 280 - Segment Reporting, the Company routinely evaluates whether its separate operating and reportable segments have changed. This determination is made based on the following factors: (1) the Company’s chief operating decision maker (“CODM”) is currently managing each operating segment as a separate business and evaluating

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the performance of each segment and making resource allocation decisions distinctly and expects to do so for the foreseeable future, and (2) discrete financial information for each operating segment is available.

Prior to the year ended December 31, 2016, the Company’s reportable segments were: (i) Completion Services, (ii) Well Support Services, and (iii) Other Services. In line with the discontinuance of the small, ancillary service lines and divisions in the Other Services reportable segment, subsequent to the year ended December 31, 2016, the Company is disclosing two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period. The Company's reportable segments are now: (i) Completion Services and (ii) Well Support Services. This segment structure reflects the financial information and reports used by the Company’s management, including its CODM, to make decisions regarding the Company’s business, including performance evaluation and resource allocation decisions. The following is a brief description of the Company's reportable segments:

Completion Services

The Company’s Completion Services segment consists of the following businesses and service lines: (1) fracturing; (2) cased-hole wireline and pumping services; (3) well construction & intervention services, which includes cementing, coiled tubing and directional drilling services; and (4) completion support services, which includes our research & technology ("R&T") department and data control instruments business.

Well Support Services

The Company’s Well Support Services segment consists of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) special services, which includes plug and abandonment, artificial lift applications and other specialty well site services.

Other Services

Other Services consisted of smaller, non-core business lines that have since been divested, including the Company's specialty chemical business, equipment manufacturing and repair business and international coiled tubing operations in the Middle East.

The following tables set forth certain financial information with respect to the Company’s reportable segments.

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	Completion Services			Well Support Services			Other Services			Corporate / Elimination			Total
Year Ended December 31, 2017 (Successor)
Revenue from external customers	$	1,256,511		$	382,228		$	—		$	—		$	1,638,739
Inter-segment revenues	610			1,437			—			(2,047		)	—
Depreciation and amortization	88,053			48,832			—			3,765			140,650
Operating income (loss)	137,014			(21,584		)	—			(131,209		)	(15,779		)
Net income (loss)	161,124			(19,390		)	—			(119,277		)	22,457
Adjusted EBITDA	221,888			9,233			—			(100,259		)	130,862
Capital expenditures	184,580			24,368			—			1,238			210,186
As of December 31, 2017 (Successor)
Total assets	$	1,159,188		$	289,642		$	—		$	160,027		$	1,608,857
Goodwill	147,515			—			—			—			147,515
Year Ended December 31, 2016 (Predecessor)
Revenue from external customers	$	599,787		$	363,768		$	7,587		$	—		$	971,142
Inter-segment revenues	947			210			29,115			(30,272		)	—
Depreciation and amortization	141,742			73,600			2,307			(209		)	217,440
Operating loss	(306,614		)	(377,707		)	(51,778		)	(133,909		)	(870,008		)
Net loss	(306,866		)	(373,695		)	(58,757		)	(204,971		)	(944,289		)
Adjusted EBITDA	(41,624		)	19,456			(5,777		)	(66,897		)	(94,842		)
Capital expenditures	17,118			14,799			8,451			17,541			57,909
As of December 31, 2016 (Predecessor)
Total assets	$	752,225		$	500,379		$	50,191		$	58,887		$	1,361,682
Goodwill	—			—			—			—			—
Year Ended December 31, 2015 (Predecessor)
Revenue from external customers	$	1,261,398		$	459,265		$	28,226		$	—		$	1,748,889
Inter-segment revenues	4,009			—			150,755			(154,764		)	—
Depreciation and amortization	199,921			71,389			5,159			(116		)	276,353
Operating loss	(882,786		)	(31,253		)	(69,129		)	(115,154		)	(1,098,322		)
Net loss	(883,494		)	(35,313		)	(68,584		)	114,849			(872,542		)
Adjusted EBITDA	51,008			68,809			(1,327		)	(71,734		)	46,756
Capital expenditures	97,283			37,540			30,444			1,054			166,321
As of December 31, 2015 (Predecessor)
Total assets	$	1,094,054		$	920,008		$	124,328		$	60,601		$	2,198,991
Goodwill	—			307,677			—			—			307,677

Management evaluates reportable segment performance and allocates resources based on total earnings (loss) before net interest expense, income taxes, depreciation and amortization, other income (expense), net gain or loss on disposal of assets, acquisition-related costs, and non-routine items (“Adjusted EBITDA”), because Adjusted EBITDA is considered an important measure of each reportable segment’s performance. In addition, management believes that the disclosure of Adjusted EBITDA as a measure of each reportable segment’s operating performance allows investors to make a direct comparison to competitors, without regard to differences in capital and financing structure. Investors should be aware, however, that there are limitations inherent in using Adjusted EBITDA as a measure of overall profitability because it excludes significant expense items. An improving trend in Adjusted EBITDA may not be indicative of an improvement in the Company’s profitability. To compensate for the limitations in utilizing Adjusted EBITDA as an operating measure, management also uses U.S. GAAP

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measures of performance, including operating income (loss) and net income (loss), to evaluate performance, but only with respect to the Company as a whole and not on a reportable segment basis.

As required under Item 10(e) of Regulation S-K of the Securities Exchange Act of 1934, as amended, included below is a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure (in thousands) on a consolidated basis for the years ended December 31, 2017, 2016 and 2015, and on a reportable segment basis for the years ended December 31, 2017, 2016 and 2015.



	Successor			Predecessor
	Years Ended December 31,
	2017			2016			2015
Net income (loss)	$	22,457		$	(944,289	)	$	(872,542	)
Interest expense, net	1,527			157,465			82,086
Income tax benefit	(39,760		)	(129,010		)	(299,093		)
Depreciation and amortization	140,650			217,440			276,353
Other (income) expense, net	(3		)	(9,504		)	(8,773		)
(Gain) loss on disposal of assets	(31,463		)	3,075			(544		)
Impairment expense	—			436,395			791,807
Acquisition-related costs	4,606			10,534			42,662
Severance, facility closures and other	5,954			34,179			16,881
Restructuring costs	11,236			30,401			—
Reorganization costs	—			55,330			—
Inventory write-down	—			35,350			31,109
Share-based compensation expense acceleration	15,658			7,792			—
Immaterial accounts payable accrual correction	—			—			(13,190		)
Adjusted EBITDA	$	130,862		$	(94,842	)	$	46,756



	Year Ended December 31, 2017 (Successor)
	Completion Services			Well Support Services			Corporate / Elimination			Total
Net income (loss)	$	161,124		$	(19,390	)	$	(119,277	)	$	22,457
Interest expense, net	634			87			806			1,527
Income tax benefit	(28,950		)	—			(10,810		)	(39,760		)
Depreciation and amortization	88,053			48,832			3,765			140,650
Other (income) expense, net	4,205			(2,281		)	(1,927		)	(3		)
Gain on disposal of assets	(7,753		)	(23,706		)	(4		)	(31,463		)
Acquisition-related costs	4,474			—			132			4,606
Severance, facility closures and other	—			5,441			513			5,954
Restructuring costs	101			250			10,885			11,236
Share-based compensation expense acceleration	—			—			15,658			15,658
Adjusted EBITDA	$	221,888		$	9,233		$	(100,259	)	$	130,862

115

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Year Ended December 31, 2016 (Predecessor)
	Completion Services			Well Support Services			Other Services			Corporate / Elimination			Total
Net loss	$	(306,866	)	$	(373,695	)	$	(58,757	)	$	(204,971	)	$	(944,289	)
Interest expense, net	706			(145		)	—			156,904			157,465
Income tax benefit	—			—			—			(129,010		)	(129,010		)
Depreciation and amortization	141,742			73,600			2,307			(209		)	217,440
Other (income) expense, net	(453		)	(3,868		)	6,979			(12,162		)	(9,504		)
(Gain) loss on disposal of assets	(1,856		)	(3,105		)	3,060			4,976			3,075
Impairment expense	105,952			321,687			8,756			—			436,395
Acquisition-related costs	202			—			209			10,123			10,534
Severance, facility closures and other	8,226			4,466			7,558			13,929			34,179
Restructuring costs	—			—			—			30,401			30,401
Reorganization costs	—			—			—			55,330			55,330
Inventory write-down	10,723			516			24,111			—			35,350
Share-based compensation expense acceleration	—			—			—			7,792			7,792
Adjusted EBITDA	$	(41,624	)	$	19,456		$	(5,777	)	$	(66,897	)	$	(94,842	)



	Year Ended December 31, 2015 (Predecessor)
	Completion Services			Well Support Services			Other Services			Corporate / Elimination			Total
Net income (loss)	$	(883,494	)	$	(35,313	)	$	(68,584	)	$	114,849		$	(872,542	)
Interest expense, net	358			(41		)	—			81,769			82,086
Income tax benefit	—			—			—			(299,093		)	(299,093		)
Depreciation and amortization	199,921			71,389			5,159			(116		)	276,353
Other (income) expense, net	350			4,101			(545		)	(12,679		)	(8,773		)
(Gain) loss on disposal of assets	(603		)	(9		)	19			49			(544		)
Impairment expense	726,678			24,700			40,429			—			791,807
Acquisition-related costs	—			—			46			42,616			42,662
Severance, facility closures and other	12,368			2,829			813			871			16,881
Inventory write-down	8,620			1,153			21,336			—			31,109
Immaterial accounts payable accrual correction	(13,190		)	—			—			—			(13,190		)
Adjusted EBITDA	$	51,008		$	68,809		$	(1,327	)	$	(71,734	)	$	46,756

Note 14 - Quarterly Financial Data (unaudited)

Summarized quarterly financial data for the years ended December 31, 2017 and 2016 are presented below (in thousands, except per share amounts).

116

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Successor
	Quarters Ended
	March 31, 2017			June 30, 2017			September 30, 2017		December 31, 2017
Revenue	$	314,194		$	390,143		$	442,652	$	491,750
Operating income (loss)	(36,408		)	(13,244		)	6,412		27,462
Income (loss) before income taxes	(35,537		)	(15,114		)	7,357		25,991
Net income (loss)	(32,301		)	(12,721		)	10,484		56,995
Net income (loss) per common share:
Basic	$	(0.58	)	$	(0.20	)	$	0.17	$	0.89
Diluted	$	(0.58	)	$	(0.20	)	$	0.17	$	0.88



	Predecessor
	Quarters Ended
	March 31, 2016			June 30, 2016			September 30, 2016			December 31, 2016
Revenue	$	269,615		$	225,168		$	232,537		$	243,822
Operating loss	(500,416		)	(182,437		)	(85,553		)	(101,602		)
Loss before reorganization items and income taxes	(522,560		)	(302,368		)	(86,636		)	(106,405		)
Net loss	(428,412		)	(291,116		)	(106,390		)	(118,371		)
Net loss per common share:
Basic	$	(3.65	)	$	(2.46	)	$	(0.90	)	$	(1.00	)
Diluted	$	(3.65	)	$	(2.46	)	$	(0.90	)	$	(1.00	)

Note 15 - Supplemental Cash Flow Disclosures

Listed below are supplemental cash flow disclosures for the year ended December 31, 2017, 2016 and 2015:



	Successor			Predecessor
	Years Ended December 31,
	2017			2016			2015
Cash paid for interest	$	(926	)	$	(19,153	)	$	(64,950	)
Cash refunded from income taxes	$	10,561		$	14,943		$	13,815
Cash paid for reorganization items	$	—		$	(24,719	)	$	—
Non-cash investing and financing activity:
Change in accrued capital expenditures	$	202		$	(3,182	)	$	(42,793	)
Non-cash consideration for business acquisition	$	138,166		$	—		$	735,125

117

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) under the Exchange Act, the Company has evaluated, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) and internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) as of the end of the period covered by this Annual Report. The Company’s disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to its management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, the Company’s principal executive officer and principal financial officer concluded that its disclosure controls and procedures were effective as of December 31, 2017.

Management’s Report Regarding Internal Control. Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of its Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles. As of December 31, 2017, management, including the Company’s Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of its internal control over financial reporting. Based on their assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2017. 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. Management’s report on internal control over financial reporting is included in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

Changes in Internal Controls Over Financial Reporting. During January 2017, immediately following the Company’s emergence from the Chapter 11 Proceeding, we implemented a new enterprise resource planning (ERP) system, SAP, as part of our plan to enhance functionality and to support our existing and future operations. During 2017, we identified control deficiencies in the design and operating effectiveness of general information technology controls (GITCs) after the implementation of the ERP system. Specifically, we did not establish effective systems development controls, program change controls and user access controls over our new ERP system. Accordingly, the automated process-level controls and manual controls dependent upon the accuracy and completeness of information derived from our new ERP system were deemed ineffective during the first six months of 2017 and into the third quarter of 2017. These GITC control deficiencies created a reasonable possibility that a material misstatement to our consolidated financial statements would not have been prevented or detected on a timely basis, and therefore we concluded that the deficiencies represented a material weakness in our internal control over financial reporting during the first six months of 2017 and into the third quarter of 2017.

The control deficiencies described above did not result in any misstatements in our consolidated financial statements as of and for the year ended December 31, 2017.

Upon identification of the deficiencies, management designed and implemented additional GITCs around our new ERP system to remediate the items noted above including: (i) assessment of IT roles and responsibilities to align individuals’ access rights commensurate with their job descriptions, (ii) periodic reviews of access rights granted to users to ensure appropriate segregation of duties, (iii) additional monitoring to track and validate changes performed by critical IT functions, (iv) change management controls around locking the new ERP system production environment and (v) implementing review and approval requirements for users with access to develop and migrate program changes. We also performed additional procedures designed to ensure the reliability of our financial reporting and related financial statements as of December 31, 2017, which included extensive monitoring controls and comprehensive look-back procedures to identify and mitigate the risk of any errors as a result of the ERP system implementation. No errors in financial information were identified through these monitoring and look-back activities.

We have determined that the actions described above have sufficiently improved the Company’s internal control over financial reporting such that as of December 31, 2017, there is not a reasonable possibility that a material misstatement of

118

the Company’s annual or interim financial statements will not be prevented or detected on a timely basis, and the material weakness has been remediated.

Except for the remediation and extensive monitoring controls discussed above, there have been no changes in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

119

Item 9B. Other Information

None.

120

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information About Our Directors and Executive Officers

The information required by this item is incorporated by reference to our definitive proxy statement for our 2018 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act, which we expect to file with the SEC within 120 days after the close of the year ended December 31, 2017.

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

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

Item 14. Principal Accounting Fees and Services

121

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

Our Consolidated Financial Statements and accompanying footnotes are included under Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

(a)(2) Financial Statements Schedules

All other schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto or will be filed within the required timeframe.

(a)(2) Exhibits

The following documents are included as exhibits to this Annual Report:




Exhibit No.		Description of Exhibit.

2.1		Second Amended Joint Plan of Reorganization (as Modified) of CJ Holding Company, et al., Pursuant to Chapter 11 of the Bankruptcy Code, dated December 15, 2016 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by C&J Energy Services Ltd. on December 22, 2016 (File No. 000-55404)).
2.2		Agreement and Plan of Merger dated as of October 25, 2017, among C&J Energy Services, Inc., Caymus Merger Sub, Inc., O-Tex Holdings, Inc., O-Tex Sellers Representative LLC and the Stockholders set forth therein (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on October 26, 2017(File No. 000-38023)).
3.1		Amended and Restated Certificate of Incorporation of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on November 9, 2017(File No. 000-38023)).
3.2		Amended and Restated Bylaws of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Quarterly Report on Form 10-Q filed on January 6, 2017(File No. 000-55404)).
3.3		Certificate of Designation of Series A Participating Cumulative Preferred Stock of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on January 9, 2017 (File No. 000-55404)).
3.4		Certificate of Elimination of Series A Participating Cumulative Preferred Stock of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on November 9, 2017 (File No. 000-38023)).
4.1		Form of specimen Warrant certificate (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
4.2		Warrant Agreement, dated as of January 6, 2017, by and between C&J Energy Services, Inc. and American Stock Transfer & Trust Company, LLC, as warrant agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
4.3		Stockholders Agreement, dated as of January 6, 2017, by and among C&J Energy Services, Inc. and the parties thereto (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
4.4		Amendment No. 1 to Stockholders Agreement, dated as of February 27, 2017, by and among C&J Energy Services, Inc. and the parties thereto (incorporated by reference to Exhibit 4.4 to the Registrant’s Annual Report on Form 10-K filed on March 2, 2017(File No. 000-55404)).
4.5		Registration Rights Agreement, dated as of January 6, 2017, by and among C&J Energy Services, Inc. and the parties thereto (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).

122



4.6		Rights Agreement, dated as of January 6, 2017, between C&J Energy Services, Inc. and American Stock Transfer & Trust Company, LLC, as Rights Agent, which includes the Form of Certificate of Designation of Series A Participating Cumulative Preferred Stock of C&J Energy Services, Inc. as Exhibit A, the Summary of Terms of Rights Agreement as Exhibit B and the Form of Right Certificate as Exhibit C (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 9, 2017(File No. 000-55404)).
4.7		Amendment No. 1 to the Rights Agreement, dated as of November 7, 2017 between C&J Energy Services, Inc. and American Stock Transfer & Trust Company, LLC, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on November 9, 2017(File No. 000-38023)).
10.1		Amended and Restated Revolving Credit and Security Agreement, dated as of May 4, 2017, by and among C&J Energy Services, Inc., the lenders party thereto and PNC Bank, National Association, as administrative agent(incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form10-Q filed on May 10, 2017(File No. 000-38023)).
10.2+		C&J Energy Services, Inc. 2017 Management Incentive Plan. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 13, 2017(File No. 000-55404)).
10.3+		First Amendment to the C&J Energy Services, Inc. 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.4+		Restricted Share Agreement (C&J Executive Employment Agreements) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.5+		Restricted Share Agreement (Restrictive Covenants) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.6+		Restricted Share Agreement (Non-Employee Directors) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.7+		Nonqualified Stock Option Agreement (C&J Executive Employment Agreements) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.8+		Nonqualified Stock Option Agreement (Restrictive Covenants) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.9		Form of Lockup Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 1, 2017(File No. 000-38023)).
10.10+		Employment Agreement by and between C&J Energy Services, Inc. and Michael Galvan (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on May 5, 2017(File No. 000-38023)).
10.11+		Employment Agreement by and between C&J Energy Services, Inc. and Sterling Renshaw (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 18, 2017 (File No. 001-38023)).
10.12+		Employment Agreement by and between C&J Energy Services, Inc. and Vic Joyce (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 19, 2017 (File No. 001-38023)).
14.1		Corporate Code of Business Conduct and Ethics (incorporated by reference to Exhibit 14.1 to the Registrant’s Current Report on Form 8-K filed on December 18, 2017(File No. 000-38023)).
14.2		Financial Code of Ethics (incorporated by reference to Exhibit 14.2 to the Registrant’s Current Report on Form 8-K filed on December 18, 2017(File No. 000-38023)).
* 21.1		List of Subsidiaries of C&J Energy Services, Inc.
* 23.1		Consent of KPMG LLP
* 31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

123



** 32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
** 32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002



*§101.INS		XBRL Instance Document
*§101.SCH		XBRL Taxonomy Extension Schema Document
* §101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
* §101.LAB		XBRL Taxonomy Extension Label Linkbase Document
* §101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
* §101.DEF		XBRL Taxonomy Extension Definition Linkbase Document



*	Filed herewith



**	Furnished, herewith in accordance with Item 601(b)(32) of Regulation S-K. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to liability under that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except as expressly set forth by specific reference in such filing.



+	Management contract or compensatory plan or arrangement

124

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, this 1st day of March, 2018.




C&J Energy Services, Inc.

By:		/s/ Donald J. Gawick
		Donald J. Gawick, President and Chief Executive Officer and Director
		(Principal Executive Officer)

By:		/s/ Mark C. Cashiola
		Mark C. Cashiola
		Chief Financial Officer
		(Principal Financial Officer)

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

125




Signatures and Capacities		Date

By:	/s/ Donald J. Gawick	March 1, 2018
	Donald J. Gawick, President and Chief Executive Officer and Director
	(Principal Executive Officer)

By:	/s/ Mark C. Cashiola	March 1, 2018
	Mark C. Cashiola, Chief Financial Officer
	(Principal Financial Officer)

By:	/s/ Michael S. Galvan	March 1, 2018
	Michael S. Galvan, Chief Accounting Officer
	(Principal Accounting Officer)

By:	/s/ Patrick Murray	March 1, 2018
	Patrick Murray, Director and Chairman of the Board

By:	/s/ Stuart Brightman	March 1, 2018
	Stuart Brightman, Director

By:	/s/ John Kennedy	March 1, 2018
	John Kennedy, Director

By:	/s/ Steven Mueller	March 1, 2018
	Steven Mueller, Director

By:	/s/ Michael Roemer	March 1, 2018
	Michael Roemer, Director

By:	/s/ Michael Zawadzki	March 1, 2018
	Michael Zawadzki, Director

126

EXHIBIT INDEX

The following documents are included as exhibits to this Annual Report.




Exhibit No.		Description of Exhibit.

2.1		Second Amended Joint Plan of Reorganization (as Modified) of CJ Holding Company, et al., Pursuant to Chapter 11 of the Bankruptcy Code, dated December 15, 2016 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by C&J Energy Services Ltd. on December 22, 2016 (File No. 000-55404)).
2.2		Agreement and Plan of Merger dated as of October 25, 2017, among C&J Energy Services, Inc., Caymus Merger Sub, Inc., O-Tex Holdings, Inc., O-Tex Sellers Representative LLC and the Stockholders set forth therein (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on October 26, 2017(File No. 000-38023)).
3.1		Amended and Restated Certificate of Incorporation of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on November 9, 2017(File No. 000-38023)).
3.2		Amended and Restated Bylaws of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Quarterly Report on Form 10-Q filed on January 6, 2017(File No. 000-55404)).
3.3		Certificate of Designation of Series A Participating Cumulative Preferred Stock of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on January 9, 2017 (File No. 000-55404)).
3.4		Certificate of Elimination of Series A Participating Cumulative Preferred Stock of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on November 9, 2017 (File No. 000-38023)).
4.1		Form of specimen Warrant certificate (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
4.2		Warrant Agreement, dated as of January 6, 2017, by and between C&J Energy Services, Inc. and American Stock Transfer & Trust Company, LLC, as warrant agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
4.3		Stockholders Agreement, dated as of January 6, 2017, by and among C&J Energy Services, Inc. and the parties thereto (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
4.4		Amendment No. 1 to Stockholders Agreement, dated as of February 27, 2017, by and among C&J Energy Services, Inc. and the parties thereto (incorporated by reference to Exhibit 4.4 to the Registrant’s Annual Report on Form 10-K filed on March 2, 2017(File No. 000-55404)).
4.5		Registration Rights Agreement, dated as of January 6, 2017, by and among C&J Energy Services, Inc. and the parties thereto (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
4.6		Rights Agreement, dated as of January 6, 2017, between C&J Energy Services, Inc. and American Stock Transfer & Trust Company, LLC, as Rights Agent, which includes the Form of Certificate of Designation of Series A Participating Cumulative Preferred Stock of C&J Energy Services, Inc. as Exhibit A, the Summary of Terms of Rights Agreement as Exhibit B and the Form of Right Certificate as Exhibit C (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 9, 2017(File No. 000-55404)).
4.7		Amendment No. 1 to the Rights Agreement, dated as of November 7, 2017 between C&J Energy Services, Inc. and American Stock Transfer & Trust Company, LLC, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on November 9, 2017(File No. 000-38023)).
10.1		Amended and Restated Revolving Credit and Security Agreement, dated as of May 4, 2017, by and among C&J Energy Services, Inc., the lenders party thereto and PNC Bank, National Association, as administrative agent(incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form10-Q filed on May 10, 2017(File No. 000-38023)).
10.2+		C&J Energy Services, Inc. 2017 Management Incentive Plan. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 13, 2017(File No. 000-55404)).
10.3+		First Amendment to the C&J Energy Services, Inc. 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).

127



10.4+		Restricted Share Agreement (C&J Executive Employment Agreements) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.5+		Restricted Share Agreement (Restrictive Covenants) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.6+		Restricted Share Agreement (Non-Employee Directors) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.7+		Nonqualified Stock Option Agreement (C&J Executive Employment Agreements) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.8+		Nonqualified Stock Option Agreement (Restrictive Covenants) under the 2017 Management Incentive Plan (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed on February 6, 2017(File No. 000-55404)).
10.9		Form of Lockup Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 1, 2017(File No. 000-38023)).
10.10+		Employment Agreement by and between C&J Energy Services, Inc. and Michael Galvan (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on May 5, 2017(File No. 000-38023)).
10.11+		Employment Agreement by and between C&J Energy Services, Inc. and Sterling Renshaw (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 18, 2017 (File No. 001-38023)).
10.12+		Employment Agreement by and between C&J Energy Services, Inc. and Vic Joyce (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 19, 2017 (File No. 001-38023)).
14.1		Corporate Code of Business Conduct and Ethics (incorporated by reference to Exhibit 14.1 to the Registrant’s Current Report on Form 8-K filed on December 18, 2017(File No. 000-38023)).
14.2		Financial Code of Ethics (incorporated by reference to Exhibit 14.2 to the Registrant’s Current Report on Form 8-K filed on December 18, 2017(File No. 000-38023)).
* 21.1		List of Subsidiaries of C&J Energy Services, Inc.
* 23.1		Consent of KPMG LLP
* 31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
** 32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
** 32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
* §101.INS		XBRL Instance Document
* §101.SCH		XBRL Taxonomy Extension Schema Document
* §101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
* §101.LAB		XBRL Taxonomy Extension Label Linkbase Document
* §101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
* §101.DEF		XBRL Taxonomy Extension Definition Linkbase Document



*	Filed herewith



**	Furnished, herewith in accordance with Item 601(b)(32) of Regulation S-K. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to liability under that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except as expressly set forth by specific reference in such filing.



+	Management contract or compensatory plan or arrangement

128

C&J Energy Services, Inc. - FORM 10-K - March 1, 2018

Attached files

C&J Energy Services, Inc. Reports