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

C&J Energy Services, Inc. - FORM 10-K - February 26, 2016

Attached files

Attached files

C&J Energy Services, Inc. Reports

file	filename
EX-31.2 - EXHIBIT 31.2 - C&J Energy Services, Inc.	cjes12312015ex-312.htm
EX-32.2 - EXHIBIT 32.2 - C&J Energy Services, Inc.	cjes12312015ex-322.htm
EX-32.1 - EXHIBIT 32.1 - C&J Energy Services, Inc.	cjes12312015ex-321.htm
EX-21.1 - EXHIBIT 21.1 - C&J Energy Services, Inc.	exhibit211listofsignifican.htm
EX-23.1 - EXHIBIT 23.1 - C&J Energy Services, Inc.	cjes12312015ex-231.htm
EX-23.2 - EXHIBIT 23.2 - C&J Energy Services, Inc.	cjes12312015ex-232.htm
EX-31.1 - EXHIBIT 31.1 - C&J Energy Services, Inc.	cjes12312015ex-311.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, 2015



¨	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: 001-35538

C&J Energy Services Ltd.

(Exact name of registrant as specified in its charter)



Bermuda		98-1188116
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Crown House, 2nd Floor 4 Par-la-Ville Rd Hamilton HM08 Bermuda (Address of principal executive offices)

(441) 279-2900

(Registrant’s telephone number, including area code)

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



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

Securities registered pursuant to Section 12(g) of the Act: None

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

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” and “smaller reporting company” in Rule 12b-2 of the Exchange Act

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

The aggregate market value of the registrant’s common shares held by non-affiliates on June 30, 2015 (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 $698.6 million.

The number of shares of the registrant’s common shares, par value $0.01 per share, outstanding at February 22, 2016, was 120,207,209.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for its 2016 Annual Meeting of Shareholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2015, are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS



		Page
PART I

Item 1.	Business	2

Item 1A.	Risk Factors	15

Item 1B.	Unresolved Staff Comments	15

Item 2.	Properties	28

Item 3.	Legal Proceedings	28

Item 4.	Mine Safety Disclosures	29

PART II

Item 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	30

Item 6.	Selected Financial Data	31

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	56

Item 8.	Financial Statements and Supplementary Data	57

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	98

Item 9A.	Controls and Procedures	98

Item 9B.	Other Information	98

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	99

Item 11.	Executive Compensation	99

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	99

Item 13.	Certain Relationships and Related Transactions, and Director Independence	100

Item 14.	Principal Accounting Fees and Services	100

PART IV

Part 15.	Exhibits, Financial Statement Schedules	101

	Signatures	105

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,” “aim,” “will,” “could,” “should,” “potential,” “would,” “may,” “probable,” “likely,” and similar expressions that convey the uncertainty of future events or outcomes, and the negative thereof, are intended to identify forward-looking statements. Forward-looking statements, which are not generally historical in nature, include those that express a belief, expectation or intention regarding our future activities, plans and goals and our current expectations with respect to, among other things:


•	our operating cash flows, the availability of capital and our liquidity;


•	our ability to comply with the financial covenant metrics contained in our debt instruments;


•	our future revenue, income and operating performance;


•	our ability to sustain and improve our utilization, revenue and margins;


•	our ability to maintain acceptable pricing for our services, including in the spot market;


•	future capital expenditures;


•	our ability to finance equipment, working capital and capital expenditures;


•	our ability to execute our long-term growth strategy, including expansion into new geographic regions and business lines;


•	our plan to continue to seek international growth opportunities, and our ability to successfully execute and capitalize on such opportunities;


•	our ability to successfully develop our research and technology capabilities and implement technological developments and enhancements; and


•	the timing and success of future acquisitions and other strategic initiatives and special projects.

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 overcapacity and declining commodity prices 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 the oil and gas exploration and production industry;


•	the inability to comply with the financial and other covenants and metrics in our debt agreements as a result of reduced revenue and financial performance or our inability to raise sufficient funds through assets sales or equity issuances should we need to raise funds through such methods;


•	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 and therefore impacts demand and pricing for our services and negatively impacts our results of operations, including potential impairment charges;


•	the loss of, or interruption or delay in operations by, one or more significant customers;


•	the failure to pay amounts when due, or at all, by one or more significant customers;


•	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;


•	an increase in interest rates;


•	changes in customer requirements in markets or industries we serve;


•	costs, delays, regulatory compliance requirements and other difficulties in executing our long-term growth strategy, including those related to expansion into new geographic regions and new business lines;


•	the effects of 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 resulting from our failure to comply, or our compliance with, new or existing environmental regulations or an accidental release of hazardous substances into the environment;


•	expanding our operations overseas;


•	the loss of, or inability to attract new, key management 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 significant possibility of accidents resulting in personal injury or death, property damage or environmental damage; and


•	accidental damage to or malfunction of equipment.

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.

Overview of Our Business

C&J Energy Services Ltd. is a Bermuda exempt company listed on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” Effective as of March 24, 2015 (the "Effective Time"), we completed the combination of C&J Energy Services, Inc. (“Legacy C&J”) with the completion and production services business (the “C&P Business”) of Nabors Industries Ltd. (“Nabors”) pursuant to that certain Agreement and Plan of Merger (as amended, the “Merger Agreement”), dated as of June 25, 2014, by and among Legacy C&J, Nabors, Nabors Red Lion Limited (subsequently renamed C&J Energy Services Ltd., “New C&J”), Nabors CJ Merger Co. and CJ Holding Co. Under the terms of the Merger Agreement, Nabors separated the C&P Business from the rest of its operations and consolidated this business under New C&J. A Delaware subsidiary of New C&J then merged with and into Legacy C&J, with Legacy C&J continuing as the surviving corporation and a direct wholly owned subsidiary of New C&J (such transactions referred to herein collectively as the “Merger”). As of the Effective Time, common shares of Legacy C&J were converted into common shares of New C&J on a 1-for-1 basis, New C&J was renamed “C&J Energy Services Ltd.” and its common shares began trading on the NYSE under the symbol "CJES", which was previously used by Legacy C&J following completion of our initial public offering in 2011. After giving effect to the Merger, Nabors owned approximately 53% of our outstanding common shares, with Legacy C&J shareholders owning the remaining 47% of our outstanding common shares. As of February 23, 2016, Nabors owns approximately 52% of our outstanding common shares.

Pursuant to Rule 12g-3(a) under the Exchange Act, New C&J is the successor issuer to Legacy C&J following the closing of the Merger and is deemed to succeed to Legacy C&J’s reporting history under the Exchange Act. References to “C&J,” the “Company,” “we,” “us” or “our” in this Annual Report are to New C&J, together with our consolidated subsidiaries when referring to periods following the completion of the Merger , and are to Legacy C&J , together with our consolidated subsidiaries when referring to periods prior to the completion of the Merger. Results for periods prior to the completion of the Merger reflect the financial and operating results of Legacy C&J, and do not include the financial and operating results of the C&P Business. Accordingly, comparisons between our consolidated results following the completion of the Merger and results from prior periods may not be meaningful.

We are one of the largest, integrated providers of completion and production services in North America. We are led primarily by the individuals who served as Legacy C&J’s executive officers prior to the completion of the Merger. We provide a full range of well construction, well completions, well support and other complementary oilfield services to oil and gas exploration and production companies primarily in North America. Our services, which are involved in the entire life cycle of the well, include directional drilling, cementing, hydraulic fracturing, cased-hole wireline, coiled tubing, rig services, fluids management services and other special well site services. We operate in all of the major oil and gas producing regions of the continental United States and Western Canada. For the last few years we have been working to establish an operational presence in key countries in the Middle East, and we currently have an office and operational facility in Dubai and an operational facility in Saudi Arabia.

Our operating and financial performance is heavily influenced by drilling, completion and production activity by our customers in the upstream industry, and thus is significantly impacted by oil and natural gas prices. However, our performance also reflects the impact of our growth strategy, including our investments in strategic initiatives designed to strengthen, expand and diversify our company through service line diversification, vertical integration and technological advancement. In implementing our acquisition strategy, in addition to the Merger, we acquired an equipment manufacturing business in 2011 and a data acquisition and control systems business in 2013. We utilize the equipment and products manufactured by these vertically integrated businesses in our day-to-day operations, and we also sell them to third-party customers in the global energy services industry. Additionally, in May 2015, we acquired a business that designs, manufactures and installs electrical submersible pump systems and accessories primarily for artificial lift applications, which are primarily used during the completion and production lifecycle of a well. During 2013, we also began organically developing a specialty chemicals supply business for completion and production services. We source many of the chemicals and fluids used in our hydraulic fracturing operations through this business, which provides cost savings to us and also gives us direct control over the design, development and supply of these products. Additionally, we have taken a multi-faceted, integrated approach to developing our directional drilling capabilities. In April 2013, we acquired a provider of directional drilling technology and related downhole tools. Building on that technology, during the first half of 2014 we began manufacturing premium drilling motors in-house and during the second quarter of 2014 we introduced our directional drilling services line to customers as a new service offering.

savings for our expanded, integrated completion services operations, which is central to our overall strategy of proactively managing our costs to maximize returns. Additionally, several of these investments are already delivering value added products and services that, in addition to producing revenue, are creating increasing demand from key customers. We believe these capabilities can also provide a competitive advantage as customers look for innovative means for extracting oil and gas in the most economical and efficient way possible.

Our principal executive offices are located at Crown House, 2nd Floor, 4 Par-la-Ville Rd, Hamilton HM08 Bermuda and our main telephone number at that address is (441) 279-2900. 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 U.S. Securities and Exchange Commission (“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.

Our Operating Segments & Strategy

We operate in three reportable business segments:


•	Completion Services, which includes the hydraulic fracturing services, cased-hole wireline services, coiled tubing services and other well stimulation services of both Legacy C&J and the C&P Business.


•	Well Support Services, which includes services acquired with the C&P Business, specifically including rig services, fluid management services and other special well site services.

•

Other Services, which include Legacy C&J’s smaller service lines and divisions, including directional drilling services, equipment manufacturing and repair, specialty chemicals sales, research and technology, and Middle East operations, as well as the C&P Business’ cementing services. We manage several of our vertically integrated business through our research and technology division, including our data acquisition and control instruments provider and artificial lift applications provider. Costs associated with general corporate activities and intersegment eliminations are also included in this Other Services segment.

Each segment is described in more detail below; for additional financial information about our segments, including revenue from external customers and total assets by segment, see Note 11 - Segment Information in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

Our operating and financial results for our core service lines, which are primarily included in our Completion Services segment and Well Support Services segment, are driven primarily by deviations in four interrelated, fluctuating variables: (1) the drilling, completion and production activities of our customers, which is 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 driven by the level of demand for our services and 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 C&J provides through efficiency gains are central to our efforts to support utilization and grow our business. Although our management team monitors asset utilization, among other factors, for purposes of assessing our overall activity levels and customer demand, asset utilization cannot be relied on as indicative of our financial and/or operational performance. 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

Our Completion Services segment consists of the following service lines: (1) hydraulic fracturing; (2) cased-hole wireline, which includes wireline logging, perforating, pressure pumping ,well site make-up and pressure testing and other complementary services; and (3) coiled tubing and other well stimulation services, including nitrogen, pressure pumping and thru-tubing services. The majority of revenue for this segment is generated by our hydraulic fracturing services line.

Our Completion Services segment consists of over 1.2 million hydraulic horsepower, over 130 wireline units and over 40 coiled tubing units, having significantly increased our asset base as a result of the Merger. However, not all of these assets are utilized fully or at all at any time, due to, among other things, scheduled maintenance and downtime. Additionally, in response to the continued deterioration in market conditions over the course of the year, we implemented aggressive cost control measures and aligned our assets with industry demand, which included stacking or idling unproductive equipment across our asset base within each service line.

For the year ended December 31, 2015, revenue from our Completion Services segment was $1.2 billion, representing approximately 70% of our total revenue, with net loss of $816.5 million and Adjusted EBITDA of $73.9 million.

Well Support Services

Our Well Support Services segment, which was acquired in the Merger as part of the C&P Business, consists of the following service lines: (1) rig services, including providing workover and well servicing rigs that are involved in routine repair and maintenance, completions, re-drilling and plug and abandonment operations; (2) fluid management services, including manufacturing, transportation, storage and disposal services for fluids used in the drilling, completion and workover of oil and gas well; and (3) other special well site services. Our rig services line is the greatest driver of revenue for this segment.

Our rig services line consists of a fleet of 519 workover rigs. Our workover services are designed to enhance the production of existing wells and generally are more complex and time consuming than normal maintenance services. 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.

Our fluid management services consists of a fleet of 1,425 fluid services trucks, 5,258 frac tanks and 30 salt water disposal wells, which supply, store, remove and dispose of specialized fluids utilized in completion and workover operations and are used in daily operations for producing wells. We provide transportation and well-site storage services for various fluids utilized in connection with drilling, completions, workover and maintenance activities. We also provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in saltwater disposal wells owned by us or a third party. Demand and pricing for our fluid management services generally correspond to demand for our rig services.

For the year ended December 31, 2015, revenue from our Well Support Services segment was $455.8 million, representing approximately 26% of our total revenue, with net loss of $1.6 million and Adjusted EBITDA of $72.3 million.

Other Services

Our Other Services segment is comprised of our smaller service lines and divisions, including cementing services, directional drilling services, equipment manufacturing and repair, specialty chemical sales, Middle East operations, and our research and technology division. We manage several of our vertically integrated business through our research and technology

division, including our data acquisition and control instruments provider and our artificial lift applications provider. Also included in the Other Services are intersegment eliminations and costs associated with activities of a general corporate nature.

Our Other Services segment contributed $76.1 million of revenue for the year ended December 31, 2015, representing approximately 4% of our total revenue, with net loss of $54.4 million and Adjusted EBITDA of ($99.4 million).

Other Information About Our Business

Geographic Areas

As a result of the Merger, we operate in all of the major oil and gas producing regions of the continental United States and Western Canada. During the year ended December 31, 2015, approximately $1.7 billion, or 97.6%, 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 $40.7 million, or 2.3%, of our 2015 consolidated revenue from operations in Canada, primarily as a result of the Canadian business that we acquired in the Merger, and approximately $2.3 million, or 0.1% of our 2015 consolidated revenue, from coiled tubing operations in Saudi Arabia.

During the year ended December 31, 2014, substantially all of our consolidated revenue from external customers was derived from the United States, and substantially all of our long-lived assets were located in the United States. In the second quarter of 2014, we positioned two of our coiled tubing units in Saudi Arabia to service our first international contract, which generated $1.0 million, or 0.1%, of our 2014 consolidated revenue.

Over the past several years, we have focused on expanding our geographic reach, both domestically and internationally. With respect to our international expansion, most of our efforts have been with respect to the Middle East and we have continued to invest in the infrastructure needed to support the development of operations in that region. In January 2014 we were awarded our first international contract to provide coiled tubing services on a trial basis in Saudi Arabia. During the first half of 2014, we established coiled tubing equipment, crews and logistics on the ground in Saudi Arabia to service this contract. We mobilized on location for our customer in late June 2014 and we successfully completed our first coiled tubing job in July 2014. We completed the scheduled work under this provisional contract in September 2015, but we have maintained a facility and employees in the country. We believe that this contract provided us with a valuable opportunity to demonstrate our services outside of the United States and we are optimistic that our efforts can lead, over time, to a long-term relationship and additional opportunities with this customer. We also hope that by demonstrating our capabilities in the region we may be able to secure additional opportunities with other customers in the Middle East. Although we are trying to obtain additional work with this customer and other key customers in the region, there is no guarantee that we will be successful in doing so. For certain risks attendant to our anticipated non-U.S. operations, please read “Risk Factors” in Part I, Item 1A of this Annual Report.

Seasonality

Our operations are subject to seasonal factors and our overall financial results reflect the seasonal variations experienced in our core service lines. Specifically, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. Additionally, our operations are directly affected by weather conditions. During the winter months our customers may delay operations or we may not be able to operate or move our equipment between locations during periods of heavy snow, ice or rain, and during the spring some areas impose transportation restrictions due to the muddy conditions caused by the spring thaws. During the summer months, our operations may be impacted by tropical weather systems.

Sales and Marketing

Sales of our core service lines in our Completion Services segment and Well Support Services segment are primarily generated by the efforts of our sales force. Due to the short lead time between ordering services and providing services, there is typically no sales backlog in our core service lines in our Completion Services segment and Well Support Services segment.

Sales and marketing activities are typically performed through our local operations in each geographic region. We believe our local field sales personnel have an excellent 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 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 U.S. and in Western Canada. One of the benefits of the Merger was the expansion and diversification of our customer base, as there was very little overlap between the top customers of Legacy C&J and the C&P Business. We monitor closely the financial condition of our customers, their capital expenditure plans and other indications of their drilling, completion and production services. In particular, we seek to identify distressed customers and apply what we believe to be appropriate business measures to protect us from any defaults or failures to pay.

Our top ten customers accounted for approximately 53.6%, 51.1% and 64.6% of our consolidated revenue for the years ended December 31, 2015, 2014 and 2013, respectively. For the year ended December 31, 2015, revenue from Oxy USA, Inc. represented 15.5% of our consolidated revenue. For the year ended December 31, 2014, revenue from Anadarko Petroleum Corporation individually represented 16.4% of our consolidated revenue. For the year ended December 31, 2013, revenue from Anadarko Petroleum Corporation and Apache Corporation individually represented 19.5% and 13.1%, respectively, of our consolidated revenue. Other than those listed above, no other customer accounted for more than 10% of our consolidated revenue in 2015, 2014 or 2013. 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 energy services industry with significant potential for excess capacity. Completion and well servicing equipment can be moved with relative ease 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. 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 are affected by short-term and long-term trends in oil and natural gas prices and numerous other factors over which we have no control. 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.

Our revenues and earnings are directly affected by changes in utilization and pricing levels for our services, which fluctuate in response to changes in the level of drilling, completion and workover activity by our customers. Pressure on pricing for our core services, including due to competition and industry and/or economic conditions, has impacted, and is expected to continue to impact, among other things, our ability to maintain utilization and pricing for our services or implement price increases. 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.

Our competitors include many energy service companies, including some of the largest integrated energy services companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can, including by reducing prices for services. Our major competitors for our Completion Services include Halliburton, Schlumberger, Baker Hughes, CalFrac Well Services, Trican, Weatherford International, RPC, Inc., Pumpco, a subsidiary of Superior Energy Services, Frac Tech, Basic Energy Services and Universal (a subsidiary of Patterson-UTI Energy, Inc.), as well as a significant number of regional businesses. Our major competitors for our Well Support Services include Halliburton, Schlumberger, Baker Hughes, Key Energy Services, Basic Energy Services, Superior Energy Services, Precision, Forbes, Pioneer, as well as a significant number of 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 as we experienced during 2015 and continue to experience to date. 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. While we must be competitive in our pricing, we believe many of our customers elect to work with us based on the safety, performance and quality of our crews, equipment and services. 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.

Research & Technology, Intellectual Property

Over the last several years we have significantly invested in our research and technology capabilities, formally commencing with the 2013 establishment of new, state-of-the-art Research and Technology Center housing a team of engineers and support staff. We believe that one of the strategic benefits of this division is the ability to develop and implement new technologies and enhancements. and respond to changes in customers’ requirements and industry demand. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers.

As a result of these efforts, starting in 2014 and continuing through 2015, we introduced several new products and progressed on differentiating technologies that we believe will provide a competitive advantage as our customers focus on extracting oil and gas in the most economical and efficient ways possible. Some of our research and technology initiatives are now generating monthly cost savings for our expanded, integrated completion services operations, which is central to our overall strategy of proactively managing our costs to maximize returns. Our equipment manufacturing division provides another platform to integrate our strategic initiatives, implement technological developments and enhancements and capture additional cost savings. Additionally, several of these investments are delivering value added products and services that are creating increasing demand from key customers.

We seek patent and trademark protections 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. In addition, we rely to a great extent on the technical expertise and know-how of our personnel to maintain our competitive position.

Suppliers

We purchase raw materials (such as proppant, guar, fracturing fluids or coiled tubing) and finished products (such as fluid-handling equipment) 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, as well as from our other smaller businesses included in our Other Services segment.

We are not dependent on any single supply source for these materials or products and we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers. During the year ended December 31, 2015, only our equipment manufacturing business and our specialty chemicals business supplied 5% or more of the materials and/or products used in our Completion Services segment, and no single supplier supplied 5% or more of the materials and/or products used in our Well Support Services segments. However, should we be unable to purchase the necessary materials and/or products, or otherwise be unable to procure the materials and/or products 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 faced sporadic proppant shortages and trucking shortages associated with hydraulic fracturing operations requiring work stoppages, which adversely impacted the operating results of several competitors. Additionally, increasing costs of certain raw materials may negatively impact demand for our services or the profitability of our business operations.

Quality, Health, Safety and Environmental ("QHSE") Program

Our business involves the operation of heavy and powerful equipment which can result in serious injuries to our employees and third parties and substantial damage to property. We commit substantial resources toward employee safety and QHSE management training programs, as well as our employee review process. We 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 provide a solid framework to ensure our operations minimize the hazards inherent in our work and meet regulatory requirements and customer demands.

Our record and reputation for safety is important to all aspects of our business. In the energy services industry, an important 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 believe that these factors will gain further importance in the future.

Risk Management and Insurance

Our operations are subject to hazards inherent in the oil and gas industry, including blowouts, explosions, cratering, fires, oil spills, hazardous materials 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 materials spills. If a serious accident were to occur involving our employees, equipment and/or services, it 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, and property damage relating to catastrophic events. 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; and property damage for catastrophic events of $25,000. However, under the terms of the Separation Agreement relating to the Merger, 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 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 relating to or resulting from any demand, claim, investigation or litigation pending or asserted in writing as of the closing of the Merger. Any liability relating to or resulting from any claim or litigation asserted after the closing of the Merger, but where the underlying cause of action arose prior to that time, would not be covered by our insurance policies.

As discussed below, our Master Service Agreements (“MSAs”) with each of our customers 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 enter into MSAs with each of our customers for our core service lines in our Completion Services segment and our Well Support Services segment. Our MSAs delineate our and our customers’ respective indemnification obligations with respect to the services we provide. Our MSAs typically provide for knock-for-knock indemnification for all losses, which means that we and our customers assume liability for damages to our respective personnel and property. For catastrophic losses, our MSAs generally include industry-standard carve-outs from the knock-for-knock indemnities, pursuant to which our customers (typically the exploration and production company) assume liability for (i) damage to the hole, 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 that we can be held responsible for events of catastrophic loss only if 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, 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.

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 22, 2016, we had 6,151 employees. We significantly increased our employee base as a result of combing Legacy C&J with the C&P Business, increasing overall headcount from 3,397 employees to 9,168 employees immediately following the closing of the Merger. However, due to the severe deterioration in market conditions over the course of 2015, we reduced our headcount as part of our continuing effort to align our business with the reduction in demand for our services, as well as due to the elimination of duplicative positions as we implemented our integration strategy following the Merger.

The delivery of our services and products requires personnel with specialized skills and experience who can perform physically demanding work. Subject to industry and local market conditions, the additional crew members needed for our core service lines in our Completion Services and Well Support Services segments are generally available for hire on relatively short notice.

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 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. 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. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

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.

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 when necessary and that we are in substantial compliance with these requirements. 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.

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. From time to time, legislation is proposed in Congress, or legal actions are initiated by environmental groups that, if successful, would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,” thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such efforts were successful, it could have a significant impact on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted. Additionally, 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, a new EPA and U.S. Army Corps of Engineers (the “Corps”) rule defining the scope of the EPA’s and the Corps’ jurisdiction over wetlands and other waters became effective. To the extent the rule expands the range of properties subject to the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. 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. 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 August 2015, the EPA announced proposed rules that would 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 proposed 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. The Bureau of Land Management (“BLM”) also proposed new rules in January 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. We do not believe our operations are currently subject to these requirements, but 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, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the development of GHG emission inventories and/or regional 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. 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; an advanced notice of proposed rule making in March 2014 under the Toxic Substances Control Act that would require companies to disclose information regarding the chemicals used in hydraulic fracturing; and proposed rules in April 2015 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 American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule, though a final decision has not yet been issued.

The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. Depending on their results, these studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

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 1B. Unresolved Staff Comments

None.

Item 1A. Risk Factors

We face many challenges and risks in the industry in which we operate. Before investing in our shares 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 shares could decline and you could lose all or part of your investment.

Risks Relating to Our Business

Our business is cyclical and dependent upon conditions in the oil and natural gas industry, which 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 exploration and production activities depends largely upon prevailing industry conditions that are influenced by numerous factors which 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 ability or willingness of the Organization of Petroleum Exporting Countries ("OPEC") to set and maintain production levels for oil;


•	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 United States;


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


•	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 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 decrease or remain depressed) generally leads to decreased spending by our customers, which in turn negatively impacts drilling, completion and production activity. In particular, the demand for new or existing drilling, completion and production work is driven by available investment capital for such work. When these capital investments decline, our customers’ demand for our services declines. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be 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, and 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 remain low or decline further, 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 highly volatile. For example, during 2015, oil prices were as high as $61 per barrel and as low as $35 per barrel, and entering 2016 we have seen them fall as low as $27 per barrel. In line with the sustained weakness and volatility in oil prices over the course of 2015, 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 continue to remain low or decline further, 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.

Since the beginning of 2011, our growth has been funded by cash flows from operations, borrowings under our credit facilities and the net proceeds we received from our initial public offering, which closed on August 3, 2011. As of December 31, 2015, we had $121.0 million outstanding under our Revolver and $12.6 million in letters of credit, and as of February 23, 2016, we had $251.0 million outstanding under our Revolver and $12.6 million in letters of credit, leaving $36.4 million available for additional borrowing based on $300.0 million of Revolver availability. As a result, we have limited ability to borrow under our Revolver until amounts outstanding have been repaid. Please see “Liquidity and Capital Resources -Description of Our Credit Agreement” in Part II, Item 7 of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information about our Revolver and other facilities under our Credit Agreement, including the financial and other restrictive covenants contained therein.

We expect to depend on recent drawings made on our Revolving Credit Facility for a portion of our future capital needs. We may draw all or a portion of the remaining $36.4 million available for additional borrowing under the Revolver in ordinary course to fund operations, build cash or other general corporate purposes. In the event we draw the full amount available under our Revolver, we will no longer have the ability to draw additional funds from the Revolver until some or all of the outstanding borrowings have been repaid. As a result, absent the issuance of additional securities, alternative financing arrangements or the repayment of outstanding borrowings under our Revolving Credit Facility, cash flow from operations and our existing cash on hand may be the sole source of funding for our operations

The successful execution of our growth strategy depends on our ability to generate sufficient cash flows and/or raise additional capital as needed. Our ability to fund future growth depends on our performance, which is impacted by factors beyond our control, including financial, business, economic and other factors, such as potential changes in customer preferences 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 the Credit Agreement and cause a cross default with respect to our other outstanding indebtedness, resulting in the acceleration of all such outstanding indebtedness. 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.

If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If we do not generate sufficient cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:


•	refinancing or restructuring all or a portion of our debt;


•	obtaining alternative financing;


•	selling assets;


•	reducing or delaying capital investments;


•	seeking to raise additional capital; or


•	revising or delaying our strategic plans.

However, we cannot assure you that we would be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that undertaking alternative financing plans would allow us to meet our debt obligations and capital requirements or that these actions would be permitted under the terms of our Credit Agreement. 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.

We are highly leveraged and our substantial indebtedness could adversely affect our operations and financial condition.

As of December 31, 2015, we had $1.2 billion of debt outstanding, excluding original issue discount, comprised of $121.0 million drawn and $12.6 million of letters of credit outstanding under our Revolving Credit Facility and $1.1 billion outstanding under a Term Loan B facility, consisting of a $570.7 million term loan B-1 that matures in 2019 and a $481.4 million term loan B-2 that matures in 2021. As of February 23, 2016, we had $251.0 million outstanding under our Revolver and $12.6 million in letters of credit, leaving $36.4 million available for borrowing, based on $300.0 million of Revolver availability. The additional draws of $130.0 million on our Revolving Credit Facility since December 31, 2015 will result in approximately $1.1 million of additional interest expense for the first quarter of 2016. Should we decide to draw all or some portion of the remaining $36.4 million available under our Revolver during the first quarter of 2016, we would incur additional amounts of interest cost to do so.

As a result of our current indebtedness, we have limited ability to borrow additional funds from the Revolver until some or all of the outstanding borrowings have been repaid. We expect to depend on recent drawings made on our Revolving Credit Facility for a portion of our future capital needs. We may draw all or a portion of the remaining $36.4 million available for additional borrowing under the Revolver in ordinary course to fund operations, build cash or other general corporate purposes. In the event we draw the full amount available under our Revolver, we will no longer have the ability to draw additional funds from the Revolver until some or all of the outstanding borrowings have been repaid. As a result, absent the issuance of additional securities, alternative financing arrangements or the repayment of outstanding borrowings under our Revolving Credit Facility, cash flow from operations and our existing cash on hand may be the sole source of funding for our operations.

C&J’s substantial 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 its cash flow from operating activities to payments on its 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 shares or pay cash dividends.

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

Our ability to meet our expense and debt service obligations under, and comply with the financial covenants contained in, the Credit Agreement depends on our future performance, which is affected by financial, business, economic and other factors, many of which are beyond our control, including potential changes in customer preferences, the success of product and marketing innovation 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, in the event that utilization and pricing levels for our services remain at or near existing levels, we may not remain in compliance with one or more of the financial covenants under the Credit Agreement in future periods. Any failure to satisfy our debt obligations or to comply with the applicable financial covenants under the Credit Agreement 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 the Credit Agreement, we may trigger an event of default under the Credit Agreement. Upon such an event of default, the lenders may refuse to fund borrowings under the Revolving Credit Facility and would have the right to terminate the commitments under the Revolving Credit Facility and potentially accelerate all amounts outstanding under the Credit Agreement. An acceleration under the Credit Agreement could also cause a cross default or cross acceleration of our other outstanding indebtedness. If an event of default occurs, or if other debt agreements cross-default, and the lenders under one or more of the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may be required to refinance all or part of our debt, sell important strategic assets or businesses at unfavorable prices or borrow more money. We may not be able to, at any given time, refinance our debt, sell assets or borrow more money on terms acceptable to us or at all. The inability to refinance the debt or access the capital markets could have a material adverse effect on our financial condition and results from operations and we could be forced into bankruptcy or liquidation.

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

The Credit Agreement governing our indebtedness contains 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, including a maximum Total Leverage Ratio based on net consolidated indebtedness to EBITDA and a minimum Interest Expense Ratio requiring a minimum quarterly ratio of consolidated EBITDA to consolidated interest expense. On September 29, 2015, the Company obtained a waiver and entered into certain amendments to the Credit Agreement that, among other things, (1) suspended the quarterly maximum Total Leverage Ratio and quarterly minimum Interest Coverage Ratio covenants, commencing with the fiscal quarter ending September 30, 2015 and continuing through the fiscal quarter ending June 30, 2017 and (2) implemented new financial covenants that apply in lieu of the quarterly maximum Total Leverage Ratio and quarterly minimum Interest Coverage Ratio covenants, including a quarterly minimum EBITDA covenant, commencing with the quarter ended September 30, 2015 and running through the quarter ending June 30, 2017.

Specifically, the restrictive covenants limit our ability and that of our subsidiaries to, among other things:


•	sell or otherwise dispose of assets;


•	make certain restricted payments and investments;


•	create, incur, assume, suffer to exist or guarantee additional indebtedness;


•	create, incur, assume, or suffer to exist liens on our assets;


•	make capital expenditures, investments or acquisitions;


•	repurchase, redeem or retire our capital shares;


•	merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;


•	engage in specified transactions with subsidiaries and affiliates; and


•	pursue other corporate activities.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by restrictive covenants under the Credit Agreement, 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 Credit Agreement” in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information about the Credit Agreement, including the financial and other restrictive covenants contained therein.

Our Credit Agreement has substantial restrictions and financial covenants which we may not be in compliance with in future periods. Noncompliance with these restrictions and financial covenants would result in an event of default under the Credit Agreement and could also cause a cross default or cross acceleration of all our other outstanding indebtedness and we could be forced into bankruptcy or liquidation.

The Credit Agreement governing our Revolving Credit Facility contains restrictive covenants that limit our ability and that of our subsidiaries to create, incur, assume or suffer to exist liens or indebtedness, sell or otherwise dispose of our assets, make certain restricted payments and investments, enter into transactions with affiliates and prepay certain indebtedness. The Credit Agreement also contains financial covenants that require us to maintain compliance with certain financial metrics. Please see “Liquidity and Capital Resources - Description of Our Credit Agreement” in Part II, Item 7 of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information about our Revolver and other facilities under our Credit Agreement, including the financial and other restrictive covenants contained therein; see also Note 2 - Long-Term Debt and Capital Lease Obligations in Part II, Item 8 “Financial Statements and Supplementary Data.”

Our ability to comply with the restrictive and financial covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances, many of which are beyond our control. Our cash flow is highly dependent on utilization levels and pricing for our services, which have declined substantially as demand for our services significantly decreased due to the sustained weakness in commodity prices. In the event that utilization and pricing levels for our services remain at or near existing levels for a sustained period, we may be unable to comply with one or more financial covenants in future periods.

If we are unable to comply with, or obtain relief from, the financial and other restrictive covenants contained in the Credit Agreement, or if we are unable to meet our debt service obligations, we may trigger an event of default under the Credit Agreement. Noncompliance with these financial covenants would result in an event of default under the Credit Agreement and could also cause a cross default or cross acceleration of all our other outstanding indebtedness. If an event of default occurs under the Credit Agreement, or if other debt agreements cross default, the lenders under one or more of the affected debt agreements could elect to declare all amounts outstanding to be immediately due and payable and terminate all commitments to extend further credit.

If the lenders under one or more of the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may be required to refinance all or part of our debt, sell important strategic assets or businesses at unfavorable prices or borrow more money. We have pledged a significant portion of our and our subsidiaries’ assets as collateral and if we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness 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 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 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.

Additionally, 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 have remained depressed through 2015, which resulted in reduced drilling activity in natural gas shale plays. This drove many energy services companies operating in those areas to relocate their equipment to more oily- and liquids-rich shale plays, such as the Eagle Ford Shale and Permian Basin. As drilling activity and completion capacity migrated into the oily- 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.

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.

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

Our top ten customers represented approximately 53.6%, 51.1% and 64.6% of our consolidated revenue for the years ended December 31, 2015, 2014 and 2013, 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 an 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 proppant shortages associated with hydraulic fracturing operations 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.

If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising prior to the ownership change to offset future taxable income.

If we were to experience an ‘‘ownership change,’’ as determined under section 382 of the Internal Revenue Code, our ability to offset taxable income arising after the ownership change with net operating losses ("NOL's") arising prior to the ownership change would be limited, possibly substantially. An ownership change would establish an annual limitation on the amount of our pre-change NOL's we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate.

Our executive officers and certain key personnel are critical to our business and these officers and key personnel may not remain with us in the future.

Our future success depends upon the continued service of our executive officers and other key personnel, particularly Joshua E. Comstock, our founder, Chief Executive Officer and Chairman of the Board of Directors. If we lose the services of Mr. Comstock, or that of our other executive officers or key personnel, our business, operating results and financial condition could be harmed. Additionally, although we maintain key person life insurance on Mr. Comstock, the proceeds from such insurance would not be sufficient to cover our losses in the event we were to lose his services.

We are vulnerable to the potential difficulties associated with rapid growth, mergers, acquisitions and expansion.

We have grown rapidly over the last several years, both organically and through acquisitions, and most notably through the Merger combining Legacy C&J with the C&P Business. We believe that our future success depends on our ability to continue 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 energy 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. 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 an 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.

We may be unable to employ a sufficient number of 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.

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, 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 rule making under the Toxic Substances and Control Act that would require the disclosure of chemicals used in hydraulic fracturing fluids. In addition, from time to time legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.

Certain governmental reviews are also either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA is performing a study of the potential environmental effects of hydraulic fracturing on drinking water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report sometime in 2015. The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards sometime in 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the

Interior, are evaluating various other aspects of hydraulic fracturing. Depending on their results, these studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

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. 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 determined that emissions of carbon dioxide, methane and other 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, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the federal CCA 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. In addition to the EPA, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the development of GHG emission inventories and/or regional 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. The Obama Administration has also announced that it intends to release a series of new regulations on the oil and gas industry in 2015, including federal standards limiting methane emissions.

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 legislation 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. 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.

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; 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. 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.

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.

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.

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 from making, offering or authorizing improper payments to non-U.S. government officials for the purpose of obtaining or retaining business. We do business and may do additional business in the future in countries or regions where strict compliance with anti-bribery laws may conflict with local customs and practices. Violations of anti-bribery laws (either due to our acts 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.

We are committed to doing business in accordance with applicable anti-corruption laws and our own internal policies and procedures. We have implemented policies and procedures concerning compliance with the FCPA that is disseminated to employees, directors, contractors, and agents. This policy has been implemented as part of our anti-bribery compliance program.

Our existing safeguards and any future improvements, however, may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible. Some foreign jurisdictions may require us to utilize local agents and/or establish joint ventures with local operators or strategic partners. Even though some of our agents and partners may not themselves be subject to the FCPA or other non-U.S. anti-bribery laws to which we may be subject, if our agents or partners make improper payments to non-U.S. government officials in connection with engagements or partnerships with us, we could be investigated and potentially found liable for violation of such anti-bribery laws and could incur civil and criminal penalties and other sanctions, which could have a material adverse effect on our business, financial position, results of operations and cash flows.

We do business in an international jurisdiction whose political and regulatory environment and compliance regimes differ from those in the United States.

During 2013 we began to establish a presence in the Middle East. We opened our first international office in Dubai, where we assembled a team of sales, operational and administrative personnel, and established relationships with partners in targeted countries. In January 2014 we were awarded our first international contract to provide coiled tubing services on a trial basis in Saudi Arabia. During the first half of the year, we established coiled tubing equipment, crews and logistics on the ground in Saudi Arabia to service this contract. We mobilized on location for our customer in late June 2014 and we successfully completed our first coiled tubing job in July 2014. We completed the scheduled work under this provisional contract in September 2015, but we have maintained a facility and employees in the country. We are optimistic that our efforts can lead, over time, to a long-term relationship and additional opportunities with this customer, which we are actively pursuing. We also hope that we may be able to secure opportunities with other potential customers in the Middle East. Risks associated with operations in foreign areas, such as the Middle East, include, but are not limited to:


•	expropriation, confiscation or nationalization of assets;


•	renegotiation or nullification of existing contracts;


•	foreign exchange limitations;


•	foreign currency fluctuations;


•	foreign taxation;


•	the inability to repatriate earnings or capital in a tax efficient manner;


•	changing political conditions;


•	changing foreign and domestic monetary policies;


•	social, political, military and economic situations in foreign areas where we do business and the possibilities of war, other armed conflict or terrorist attacks; and


•	regional economic downturns.

Risks Related to Our Common Shares

Our common share price has been volatile, and we expect it to continue to remain volatile in the future.

The market price of common shares of companies engaged in the oil and gas services industry has been highly volatile. Likewise, the market price of our common shares has varied significantly in the past (52-week range has been $0.82 to $18.45), and we expect it to continue to remain volatile given the cyclical nature of our industry.

If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common shares, which would have an adverse impact on the trading volume, liquidity and market price of our common shares.

On February 25, 2016, the closing price of our common shares fell below $1.00 per share. If the average closing price of our common shares were to fall below $1.00 over a period of 30 consecutive trading days, which is the minimum average share price required by the NYSE under Section 802.01C of the NYSE Listed Company Manual, we would no longer be in compliance with the NYSE’s continued listing requirements and would expect to receive a notice of noncompliance from the

NYSE. The notice would have no immediate impact on the listing of our common shares, which would continue to be listed and traded on the NYSE during the six-month period described below, subject to our compliance with other continued listing standards.

We would have six months following receipt of the NYSE’s notice to regain compliance with the NYSE’s minimum share price requirement. We would be able to regain compliance at any time during the six-month cure period if on the last trading day of any calendar month during the cure period our common shares has a closing share price of at least $1.00 and an average closing share price of at least $1.00 over the 30 trading-day period ending on the last trading day of such month. Notwithstanding the foregoing, if we were to determine that we must cure the price condition by taking an action that will require approval of our shareholders (such as a reverse stock split), we could also regain compliance by: (i) obtaining the requisite shareholder approval by no later than our next annual meeting, (ii) implementing the action promptly thereafter, and (iii) the price of our common shares promptly exceeding $1.00 per share, and the price remaining above that level for at least the following 30 trading days. However, if at any time our common share price drops to the point where the NYSE considers the price to be "abnormally low," the NYSE has the discretion to begin delisting proceedings immediately. While there is no formal definition of "abnormally low" in the NYSE rules, the NYSE has recently delisted the common stock of issuers when it trades below $0.16 per share. In addition, the NYSE will promptly initiate suspension and delisting procedures if the NYSE determines that we have an average global market capitalization over a consecutive 30 trading-day period of less than $15.0 million.

A delisting of our common shares from the NYSE could negatively impact us as it would likely reduce the liquidity and market price of our common shares; reduce the number of investors willing to hold or acquire our common shares; and negatively impact our ability to access equity markets and obtain financing.

Future issuances by us of common shares or convertible securities could lower our share price and dilute your ownership in us.

As of February 22, 2016, we had 120,207,209 common shares outstanding. We are currently authorized to issue up to 750,000,000 common shares and 50,000,000 preferred shares with terms designated by our Board of Directors. In the future, we may, from time to time, issue additional common shares or securities convertible into common shares in public offerings or privately negotiated transactions. We cannot predict the size of future issuances of common shares or securities convertible into common shares or the effect, if any, that future issuances and sales of common shares will have on the market price of our common shares. Sales of substantial amounts of common shares (including shares issued in connection with an acquisition or employee benefit plan), or the perception that such sales could occur, may adversely affect prevailing market prices of our common shares and dilute your ownership interest in us.

As a result of the Merger, the majority of our common shares are held by Nabors.

Holders of our common shares will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or our memorandum of association or bye-laws. As a result of the Merger, Nabors (through one of its wholly-owned subsidiaries) currently owns approximately 52% of our issued and outstanding common shares. Although Nabors is subject to certain standstill restrictions, during the period commencing on the closing date of the Merger and ending upon the earlier to occur of the five-year anniversary of the effective date of the Merger and the date that Nabors beneficially owns less than 15% of our issued and outstanding common shares (the "Standstill Period"), Nabors has the right to vote its majority shares in its discretion. Further, Nabors has the right to ensure that three individuals who are either Nabors employees or independent directors selected by Nabors serve on our board of directors during the Standstill Period, and such individuals may remain on our board of directors following the end of the Standstill Period. In addition, until the later to occur of the termination of the Standstill Period and the two-year anniversary of the closing date of the Merger, Nabors has preemptive rights to purchase its pro-rata portion of any common shares or other equity securities issued by us. Our amended bye-laws provide that, until the fifth anniversary of the closing date of the Merger, certain major transactions, including any sale of our Company or any amendment to our memorandum of association or amended bye-laws, require the approval of the holders of at least two-thirds of our issued and outstanding common shares, and in certain circumstances the approval of a specified number of the members of our board of directors. As a result, Nabors may be able to prevent the approval of such matters, and therefore may be able to prevent transactions that would be beneficial to us, including a change in control of our Company or other transaction that would otherwise provide our shareholders an opportunity to receive a premium for their common shares. The existence of significant shareholders may also have the effect of deterring a would-be acquirer of our Company from proposing a transaction or delaying or preventing changes in control or changes in management. In addition, Nabors may be able to influence our management because of its substantial shareholding.

Under the provisions of our bye-laws , until the end of the Standstill Period, the rights of our shareholders (including Nabors) to change the amended bye-laws relating to the election of directors and the removal of directors are subject to restrictions.

Additionally, any sale by Nabors of our common shares or any announcement by Nabors that it has decided to sell our common shares, or the perception by the investment community that Nabors has sold or decided to sell our common shares, could have an adverse impact on the price of our common shares.

In any of these matters, the interests of Nabors may differ or conflict with the interests of our other shareholders. Moreover, this concentration of share ownership may also adversely affect the trading price of our common shares to the extent investors perceive a disadvantage in owning shares of a company with a majority shareholder.

Under the rules of the NYSE, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a "controlled company" and may elect not to comply with the requirements that a majority of its board of directors consist of independent directors, that its board of directors' compensation committee be comprised solely of independent directors, and that director nominees be selected or recommended to the board of directors for selection by independent directors. Although we qualify as a "controlled company" under the NYSE rules, we are not relying on this exemption and we intend to fully comply with all corporate governance requirements under the NYSE rules. However, if we were to utilize some or all of these exemptions, our shareholders may not have the same protections afforded to shareholders of companies that are subject to all of the NYSE rules regarding corporate governance.

If Nabors sells a controlling interest in C&J to a third party in a private transaction, our shareholders may not realize any change-of-control premium on our common shares and we may become subject to the control of a presently unknown third party.

As a result of the Merger, Nabors (through one of its wholly-owned subsidiaries) currently owns approximately 52% of our issued and outstanding common shares. Nabors has agreed that, during the Standstill Period, it will transfer our common shares only to any person or "group" (within the meaning of Section 13(d)(3) of the Exchange Act) who has not filed a Schedule 13D with regard to C&J and is not required to file a Schedule 13D after giving effect to such transfer. However, following the end of the Standstill Period, or upon waiver of the standstill restrictions, should it continue to own a significant equity interest in C&J and choose to do so, Nabors may sell some or all of the C&J common shares that it owns in a privately negotiated transaction, which, if sufficient in size, could result in a change of control of C&J. The ability of Nabors to privately sell our common shares after the end of the Standstill Period, with no requirement for a concurrent offer to be made to acquire all of our other common shares, could prevent our shareholders from realizing any change-of-control premium on our common shares that may otherwise accrue to Nabors upon its private sale of our common shares. Additionally, if Nabors privately sells its significant equity interest in C&J, we may become subject to the control of a presently unknown third party. Such third party may have conflicts of interest with other our shareholders.

Provisions in our organizational documents, as well as Bermuda law, could delay or prevent a change in control of our company, which could adversely affect the price of our common shares.

The existence of certain provisions in our memorandum of association and bye-laws, as well as under Bermuda law, could delay or prevent a change in control of our company that a shareholder may consider favorable, which could adversely affect the price of our common shares. The provisions in our organizational documents that could delay or prevent an unsolicited change in control of our company include board authority to issue preferred shares without shareholder approval. If our board of directors elects to issue preferred shares, it could be more difficult for a third party to acquire the Company. In addition, some provisions of our bye-laws could make it more difficult for a third party to acquire control of our Company, even if the change of control would be beneficial to our shareholders, including provisions which:

•limit the removal and replacement of directors, including provisions relating to the classified board of directors;

•limit the ability of shareholders to increase the number of directors;

•establish preemptive rights; and

•establish advance notice and certain information requirements for nominations for election to our board of directors.

We may issue preferred shares on terms that could adversely affect the voting power or value of our common shares.

Our bye-laws authorize our Board of Directors to issue, without the approval of its shareholders, one or more classes or series of preferred shares having such designations, preferences, limitations and relative rights, including preferences over its common shares respecting dividends and distributions, as the Board may determine. The terms of one or more classes or series

of preferred shares could adversely affect the voting power or value of our common shares. For example, we might grant holders of preferred shares the right to elect some number of its 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 shares could affect the residual value of the common shares.

Future offerings of debt securities and preferred shares, which would rank senior to our common shares upon liquidation, may adversely affect the market value of our common shares.

In the future, we may, from time to time, attempt to increase our capital resources by making offerings of debt or additional offerings of equity securities, including commercial paper, medium-term notes, senior or subordinated notes and classes of preferred shares. Upon liquidation, holders of our debt securities and preferred shares and lenders with respect to other borrowings will receive a distribution of our available assets prior to the holders of our common shares. Our preferred shares, which may be issued without shareholder approval, if issued, could have a preference on liquidating distributions or a preference on dividend payments that would limit amounts available for distribution to holders of our common shares. Because our decision to issue securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings. Thus, holders of our common shares bear the risk that our future offerings may reduce the market value of our common shares.

Item 2. Properties

Our principal executive headquarters are located at Crown House, 2nd Floor, 4 Par-la-Ville Road, Hamilton, Bermuda, and our U.S. corporate headquarters are located at 3990 Rogerdale Rd., Houston, Texas 77042. We own or lease facilities and administrative offices throughout the geographic regions in which we operate. As of February 22, 2016, we own or lease the following principal properties:



Location	Type of Facility	Size	Lease or Own	Expiration of Lease
3990 Rogerdale Road, Houston, TX	Headquarters	125,000 sq. ft. building	Lease	February 21, 2025
Crown House, 2nd Floor, 4 Par-la-Ville Road, Hamilton, Bermuda	Headquarters	2,740 sq. ft. building	Lease	March 31, 2017
4460 Hwy 77 Robstown, TX	Administrative offices, warehouse, maintenance shop, equipment yard	15 acres, 61,000 sq. ft. building	Own	—
Plot No. S40320 & S40321, Dubai, UAE	Administrative offices, warehouse, maintenance shop, equipment yard	14 acres, 104,755 sq. ft. building	Lease	June 30, 2028
10771 Westpark Drive, Houston, TX	Administrative offices, R&T Lab & Tech Center	84,023 sq. ft. building	Lease	October 31, 2025

In addition to the principal properties listed above, we own or lease numerous other smaller facilities across our operating areas, 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 that all of our existing properties are suitable for their intended uses and sufficient to support our operations. We do not believe that any single property is material to our operations and, if necessary, we could readily obtain a replacement facility. We continuously evaluate the needs of our business, and we will purchase or lease additional properties or consolidate our properties, as our business requires.

Item 3. Legal Proceedings

We are subject to various legal proceedings and claims incidental to or arising in the ordinary course of our business. Our management does not expect the outcome in any of these known legal proceedings, individually or collectively, to have a material adverse effect on our consolidated financial condition or results of operations.

In July 2014, following the announcement that Legacy C&J, Nabors, and New C&J had entered into the Merger Agreement, a putative class action lawsuit was filed by a purported shareholder of Legacy C&J challenging the Merger. The lawsuit is styled City of Miami General Employees’ and Sanitation Employees’ Retirement Trust, et al. (“Plaintiff”) 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 “Merger Lawsuit”). Plaintiff in the Merger Lawsuit generally alleges that the board of directors for Legacy C&J breached fiduciary duties of loyalty, due care, good faith, candor and independence by allegedly approving the Merger Agreement at an unfair price and through an unfair process. Plaintiff alleges that the Legacy C&J board directors, or certain of them (i) failed to fully inform themselves of the market value of Legacy C&J, maximize its value and obtain the best price reasonably available for Legacy C&J, (ii) acted in bad faith and for improper motives, (iii) erected barriers to discourage other strategic alternatives and (iv) put their personal interests ahead of the interests of Legacy C&J shareholders. The Merger Lawsuit further alleges that Legacy C&J, Nabors and New C&J aided and abetted the alleged breaches of fiduciary duties by the Legacy C&J board of directors.

On November 10, 2014, Plaintiff filed a motion for a preliminary injunction. On November 24, 2014, the Court of Chancery entered a bench ruling, followed by a written order on November 25, 2014, that (i) ordered certain members of the Legacy C&J board of directors to solicit for a period of 30 days alternative proposals to purchase Legacy C&J (or a controlling stake in Legacy C&J) that was superior to the Merger, and (ii) preliminarily enjoined Legacy C&J from holding its shareholder meeting until it had complied with the foregoing. The order provided that the solicitation of proposals consistent with the order, and any subsequent negotiations of any alternative proposal that emerges, would not constitute a breach of the Merger Agreement in any respect.

Legacy C&J complied with the Court of Chancery’s order while it simultaneously pursued an expedited appeal of the Court of Chancery’s order to the Supreme Court of the State of Delaware. On November 26, 2014, in response to, and in compliance with, the Court of Chancery’s order, the Legacy C&J board of directors established a special committee, which retained separate legal and financial advisors, to proceed with the ordered solicitation.

On December 19, 2014, following oral argument, the Delaware Supreme Court overturned the decision of the Court of Chancery and vacated the order. As such, Legacy C&J’s special committee immediately discontinued the solicitation required by the order. On March 25, 2015, the C&J Defendants moved to dismiss the complaint and filed their opening brief in support on September 15, 2015. On October 29, 2015, Plaintiff filed an amended complaint naming additional defendants and generally alleging, in addition to the allegations described above, that (i) the special committee of the Legacy C&J board of directors and its advisors improperly conducted the court-ordered solicitation that the Delaware Supreme Court vacated, and (ii) the proxy statement filed in connection with the Merger contains alleged misrepresentations and omits allegedly material information concerning the Merger and court-ordered solicitation process. The Lawsuit asserts, in addition to the claims described above, claims for breach of fiduciary duty and aiding and abetting breach of fiduciary duty against the special committee of the Legacy C&J board of directors, its financial advisor Morgan Stanley, and certain employees of Legacy C&J. The defendants in the Lawsuit have filed motions to dismiss the amended complaint. A hearing on these motions to dismiss is currently set for April 26, 2016.

We cannot predict the outcome of this or any other lawsuit that might be filed, nor can we predict the amount of time and expense that will be required to resolve the Merger Lawsuit. We believe the Merger Lawsuit is without merit and we intend to defend against it vigorously.

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 “CJES.” As of February 22, 2016, we had 120,207,209 common shares issued and outstanding, held by approximately 15 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
Year Ended December 31, 2014
Quarter ended March 31, 2014	$	29.73	$	20.26
Quarter ended June 30, 2014	$	34.93	$	27.41
Quarter ended September 30, 2014	$	34.18	$	26.90
Quarter ended December 31, 2014	$	30.81	$	11.38
Year Ended December 31, 2015
Quarter ended March 31, 2015	$	14.08	$	9.11
Quarter ended June 30, 2015	$	18.45	$	11.05
Quarter ended September 30, 2015	$	13.36	$	2.97
Quarter ended December 31, 2015	$	6.23	$	3.26
Period from January 1, 2016 to February 24, 2016	$	4.97	$	0.82

On February 24, 2016, the last reported sales price of our common shares on the NYSE was $1.09 per share.

We have not declared or paid any cash dividends on our common shares. 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 shares in the foreseeable future. Payments of dividends, if any, will be at the discretion of our Board and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our Board. Additionally, covenants contained in our Credit Facility restrict the payment of cash dividends on our common shares. 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; Use of Proceeds from Registered Securities

None.

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, 2015 (in thousands, except average price paid per share). All of the repurchases below are common 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 NYSE closing price of our common shares on the vesting date.



	Total Number of Shares Purchased (a)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number of Shares that may yet be Purchased Under Such Program
January 1—January 31	—	—		—	—
February 1—February 28	139,366	$	11.46	—	—
March 1—March 31	358	12.50		—	—
April 1—April 30	9,825	14.80		—	—
May 1—May 31	57	17.40		—	—
June 1—June 30	65,409	14.35		—	—
July 1—July 31	3,180	12.22		—	—
August 1—August 31	492	7.72		—	—
September 1—September 30	—	—		—	—
October 1—October 31	1,394	3.90		—	—
November 1—November 30	1,402	4.58		—	—
December 1—December 31	912	5.91		—	—


(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 NYSE 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 Merger, which may affect the comparability of the Selected Financial Data:



	Years Ended December 31,
	2015			2014		2013		2012		2011

	(In thousands except per share amounts)
Revenue	$	1,748,889		$	1,607,944	$	1,070,322	$	1,111,501	$	758,454
Net income (loss)	(872,542		)	68,823		66,405		182,350		161,979
Net income (loss) per common share
Basic	(8.48		)	1.28		1.25		3.51		3.28
Diluted	(8.48		)	1.22		1.20		3.37		3.19
Total assets	2,232,906			1,612,746		1,132,300		1,012,757		537,849
Long-term debt and capital lease obligations, excluding current portion	1,142,077			349,875		164,205		173,705		—

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 about the Merger Transaction

Effective as of March 24, 2015 (the "Effective Time"), we completed the combination of C&J Energy Services, Inc. (“Legacy C&J”) with the completion and production services business (the “C&P Business”) of Nabors Industries Ltd. (“Nabors”) pursuant to that certain Agreement and Plan of Merger (as amended, the “Merger Agreement”), dated as of June 25, 2014, by and among Legacy C&J, Nabors, Nabors Red Lion Limited (subsequently renamed C&J Energy Services Ltd., “New C&J”), Nabors CJ Merger Co. and CJ Holding Co. Under the terms of the Merger Agreement, Nabors separated the C&P Business from the rest of its operations and consolidated this business under New C&J. A Delaware subsidiary of New C&J then merged with and into Legacy C&J, with Legacy C&J continuing as the surviving corporation and a direct wholly owned subsidiary of New C&J (such transactions referred to herein collectively as the “Merger”). As of the Effective Time, common shares of Legacy C&J were converted into common shares of New C&J on a 1-for-1 basis, New C&J was renamed “C&J Energy Services Ltd.” and its common shares began trading on the NYSE under the symbol "CJES", which was previously used by Legacy C&J following completion of our initial public offering in 2011. After giving effect to the Merger, Nabors owned approximately 53% of our outstanding common shares, with Legacy C&J shareholders owning the remaining 47% of our outstanding common shares. As of February 23, 2016, Nabors owns approximately 52% of our outstanding shares. We are currently led primarily by the individuals who served as Legacy C&J’s executive officers prior to the completion of the Merger.

Pursuant to Rule 12g-3(a) under the Exchange Act, New C&J is the successor issuer to Legacy C&J following the closing of the Merger and is deemed to succeed to Legacy C&J’s reporting history under the Exchange Act. Because Legacy C&J was considered the accounting acquirer in the Transactions under U.S generally accepted accounting principles (“GAAP”), Legacy C&J is also considered the accounting predecessor of C&J Energy Services Ltd. Accordingly, the historical financial statements of C&J Energy Services Ltd. that cover periods prior to the completion of the Merger, reflect the assets, liabilities and operations of C&J Energy Services, Inc., the predecessor to C&J Energy Services Ltd., and do not reflect the assets, liabilities and operations of the C&P Business. Accordingly, comparisons between our consolidated results following the completion of the Merger and results from prior periods may not be meaningful.

References to “C&J,” the “Company,” “we,” “us” or “our” in this Annual Report are to New C&J, together with our consolidated subsidiaries when referring to periods following the completion of the Merger , and are to Legacy C&J , together with our consolidated subsidiaries when referring to periods prior to the completion of the Merger.

Overview

We are one of the largest, integrated providers of completion and production services in North America. We provide a full range of well construction, well completions, well support and other complementary oilfield services to oil and gas exploration and production companies primarily in North America. Our services, which are involved in the entire life cycle of the well, include directional drilling, cementing, hydraulic fracturing, cased-hole wireline, coiled tubing, rig services, fluids management services and other special well site services. We operate in all of the major oil and gas producing regions of the continental United States and Western Canada. For the last few years we have been working to establish an operational presence in key countries in the Middle East, and we currently have an office and operational facility in Dubai and an operational facility in Saudi Arabia.

Growth Strategy and Strategic Initiatives

Over the last few years, we have significantly invested in the execution of our long term growth strategy, which is focused on strengthening, expanding and diversifying our business through (1) the growth of our assets, customer base and geographic reach, both domestically and internationally, for our core service lines and (2) strategic initiatives advancing service line diversification; vertical integration and technological advancement.

Growth of Core Service Lines

During 2015, we continued to focus on growing our core business through the expansion of our assets, customer base and geographic reach, both domestically and internationally, and most notably through the Merger. The combination of Legacy C&J with the C&P Business greatly expanded our scale, service offerings and geographic reach, increasing capacity for our existing services offerings and providing diversification through the additional services offerings of the C&P Business with a stronger presence in all major domestic basins. With the Merger closing during the early part of the market downturn, we have not yet been able to fully capitalize on many of the opportunities that we believe are available both domestically and internationally through our greater scale, enhanced offerings and significant operating efficiencies.

Service Line Diversification, Vertical Integration & Technological Advancement

During 2015, we further advanced our ongoing strategic initiatives designed to strengthen, expand and diversify our business through service line diversification, vertical integration and technological advancement. In implementing our long term growth strategy, in addition to the diversification of our services through the Merger, in May 2015, we acquired an integrated business that designs, manufactures and installs electrical submersible pump systems and accessories primarily for artificial lift applications. In addition to offering a wide variety of products that support artificial lift installations, we are also developing a line of electrical submersible pump systems that are optimized for the small casing sizes typical of long horizontal wells. We believe that this business has significant growth potential when the market eventually recovers, both in the U.S. and abroad and also has the potential to provide a competitive advantage for our Well Support Services segment.

Additionally, we acquired an equipment manufacturing business in 2011 and a data acquisition and control systems business in 2013. We utilize the equipment and products manufactured by these vertically integrated businesses in our day-to-day operations, and we also sell them to third-party customers in the global energy services industry. During 2013, we also began organically developing a specialty chemicals supply business for completion and production services. We source many of the chemicals and fluids used in our hydraulic fracturing operations through this business, which provides cost savings to us and also gives us direct control over the design, development and supply of these products. Additionally, we have taken a multi-faceted, integrated approach to developing our directional drilling capabilities. In April 2013, we acquired a provider of directional drilling technology and related downhole tools. Building on that technology, during the first half of 2014 we began manufacturing premium drilling motors in-house and during the second quarter of 2014 we introduced our directional drilling services line to customers as a new service offering.

Over the last several years we have also significantly invested in our research and technology capabilities, including the development of a state-of-the-art research and technology center with a team of engineers and support staff. We believe that one of the strategic benefits of this division is the ability to develop and implement new technologies and respond to changes in customers’ requirements and industry demand. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. Several of our research and technology initiatives are now generating monthly cost savings for our expanded, integrated completion services operations, which is central to our overall strategy of proactively managing our costs to maximize returns. Additionally, several of these investments are already delivering value added products and services that, in addition to producing revenue, are creating increasing demand from key customers.

As a result of these efforts, in 2015, we introduced several new products and progressed on differentiating technologies that we believe will provide a competitive advantage as our customers focus on extracting oil and gas in the most economical and efficient ways possible.

Our Operating Segments

We currently operate in three reportable business segments:


•	Completion Services, which includes the hydraulic fracturing services, cased-hole wireline services, and coiled tubing services and other well stimulation services lines of both Legacy C&J and the C&P Business.


•	Well Support Services, which includes services lines acquired with the C&P Business, specifically including rig services, fluid management services and other special well site services.

•

Other Services, which include Legacy C&J’s smaller service lines and divisions, including directional drilling services, equipment manufacturing and repair, specialty chemicals sales, research and technology, and Middle East operations, as well as the C&P Business’ cementing services line. We also manage several of our vertically integrated business through our research and technology division, including our data acquisition and control instruments provider and artificial lift applications provider. Costs associated with general corporate activities and intersegment eliminations are also included in this Other Services segment.

Due to the transformative nature of the Merger, upon closing of the Merger, our chief operating decision maker (the “CODM”) changed the way in which the Company is managed, including a revised operating segment approach in making performance evaluation and resource allocation decisions. Discrete financial information was created to provide the information necessary for our CODM to manage our combined company under the revised operating segment structure. As a result of this change in operating segments, we revised our reportable segments during the first quarter of 2015. The current reportable business segment structure reflects the financial information and reports used by management, including our CODM, to make decisions regarding our business, including with respect to evaluating performance and allocating resource. We have recast the segment information included in this Annual Report to reflect the new reportable segment structure in order to conform to the current year presentation.

Our reportable business segments are described in more detail below; for financial information about our segments, including revenue from external customers and total assets by segment, see “Note 11 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

Completion Services

Our Completion Services segment currently consists of the following service lines: (1) hydraulic fracturing; (2) cased-hole wireline, which includes wireline logging, perforating, pressure pumping ,well site make-up and pressure testing and other complementary services; and (3) coiled tubing and other well stimulation services, including nitrogen and pressure pumping services. The majority of revenue for this segment is generated by our hydraulic fracturing services line.

Management evaluates our Completion Services segment operations’ performance and allocates resources primarily based on Adjusted EBITDA because it provides important information to us 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, transaction costs, and non-routine items.

For the year ended December 31, 2015, revenue from our Completion Services segment was $1.2 billion, representing approximately 70% of our total revenue, compared with revenue of $1.6 billion for the year ended December 31, 2014, which represents a 23% year-over-year decrease. Adjusted EBITDA from this segment for the year ended December 31, 2015 was $73.9 million, compared with $344.7 million of Adjusted EBITDA for the year ended December 31, 2014, which represents a 79% year-over-year decrease. Even with our significantly expanded asset base and diversified market presence as a result of the Merger, our financial results declined as a result of the extremely challenging market conditions that characterized the year. Specifically, revenue and Adjusted EBITDA were negatively impacted by significantly lower overall utilization and pricing levels experienced to varying degrees across our service lines and markets during the 2015 year, resulting from decreased demand by our customers in an extremely competitive environment caused by the continued decline in U.S. onshore drilling and completion activity as a result of depressed commodity prices.

With respect to the fourth quarter of 2015, revenue from our Completion Services segment was $256.6 million, representing approximately 63% of our total revenue, compared with revenue of $256.9 million for the third quarter of 2015.

Fourth quarter Adjusted EBITDA from this segment was $10.0 million, compared to Adjusted EBITDA of ($8.6 million) for the third quarter of 2015, which represents a 217% sequential increase. Utilization levels for our Completion Services improved entering the fourth quarter, although we continued to experience significant pricing pressure throughout the quarter and activity declined with the typical year-end seasonal slowdown. Hydraulic fracturing activity was strong in October, but as we moved through the quarter and activity slowed, we strategically stacked additional equipment and focused on capturing higher overall utilization levels across our active equipment base. Our strategy, which included concentrating on key customers in core basins, aggressively managing our operational cost structure and stacking our lower utilized equipment, produced improved profitability despite the challenging headwinds we faced in the back half of the quarter. In our coiled tubing service line, utilization increased at the beginning of the quarter, but activity began to decline as the effects of the seasonal slowdown impacted our operations and customers delayed previously scheduled work. In our wireline service line, both pricing and utilization remained depressed and continued to weaken with the falling rig count, seasonal slowdown and inclement weather experienced during the course of the quarter.

As we entered the first quarter of 2016, our Completion Services segment experienced a significant decline in activity that has remained depressed. We are keeping a sharp focus on managing our operations and controlling costs, including closing additional facilities, further reducing headcount, stacking idle equipment and lowering our cost structure to ensure our operations remain aligned with market conditions. The implementation of this strategy over the course of the fourth quarter enabled us to protect market share and deliver an approximate $18.6 million sequential improvement in Adjusted EBITDA for this segment. We will continue to focus on servicing the needs of our core customer base, and make the appropriate decisions as needed, to more effectively align our operations with current market conditions.

Well Support Services

Our Well Support Services segment, which was acquired in the Merger as part of the C&P Business, currently consists of the following service lines: (1) rig services, including providing workover and well servicing rigs that are involved in routine repair and maintenance, completions, re-drilling and plug and abandonment operations; (2) fluid management services, including manufacturing, transportation, storage and disposal services for fluids used in the drilling, completion and workover of oil and gas well; and (3) other special well site services. Our rig services line is the greatest driver of revenue for this segment.

Our Well Support Services segment consists of 519 workover rigs utilized by the rig services line and a fleet of 1,425 fluid services trucks, 5,258 frac tanks and 30 salt water disposal wells utilized by our fluid management services line. However, not all of these assets are utilized fully or at all at any time, due to, among other things, scheduled maintenance and downtime. Additionally, in response to the continued deterioration in market conditions over the course of the year, we implemented aggressive cost control measures and aligned our assets with industry demand, which included stacking or idling unproductive equipment across our asset base within each service line.

Management evaluates our Well Support Services segment operations’ performance 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 period from the Merger date, March 24, 2015 through December 31, 2015 (dollars in millions):



	Year Ended
	December 31, 2015

Revenue	$	455.8
Adjusted EBITDA	$	72.3
Total rigs	519
Total rig hours	465,926
Total trucks	1,425
Total truck hours	1,653,417

For the year ended December 31, 2015, revenue from our Well Support Services segment was $455.8 million, representing approximately 26% of our total revenue. Adjusted EBITDA from this segment for the year ended December 31, 2015 was $72.3 million. The entire Well Services segment was acquired in connection with the Merger; as such, we had no revenues or Adjusted EBITDA from this segment for the year ended December 31, 2014.

With respect to the fourth quarter of 2015, revenue from our Well Support Services segment was $135.7 million, representing approximately 33% of our total revenue, compared to revenue of $150.9 million for the third quarter of 2015, which represents a 10% decrease quarter over quarter.

Fourth quarter Adjusted EBITDA from this segment was $22.3 million, compared to Adjusted EBITDA of $23.6 million for the third quarter of 2015, which represents a 6% sequential decrease.

Revenue from our Well Support Services segment was negatively impacted by the typical year-end slowdown and continued pricing pressure. Despite increased demand for our services in October, the seasonal slowdown around the holidays resulted in rigs being released in several core operating basins. We also encountered some weakness in areas that typically maintain strong fourth quarter activity, such as Canada, due to low commodity prices. During the quarter, we supported utilization and protected market share through pricing concessions, while repositioning equipment and resources in line with market conditions and customer demand. Despite declining revenue, our continued focus on restructuring this segment, enhancing efficiencies and aggressively reducing costs, allowed us to generate a sequential Adjusted EBITDA margin increase of approximately 80 basis points.

As with our Completion Services segment, activity and pricing levels for our Well Support Services segment declined and have remained depressed entering the first quarter of 2016. Our customers continue to focus on lowering their costs due to the continued weakness in commodity prices, and we will continue to work with them to the best of our ability to sustain utilization, protect market share and capitalize on strategic opportunities.

Other Services

The Other Services segment is comprised of Legacy C&J’s smaller service lines and divisions, currently including directional drilling services, equipment manufacturing and repair, data acquisition and control instruments, artificial lift applications, specialty chemical sales, Middle East operations, and research and technology, as well as the C&P Business' cementing operations. Also included in the Other Services are intersegment eliminations and costs associated with activities of a general corporate nature.

Our Other Services segment contributed $76.1 million of revenue for the year ended December 31, 2015, representing approximately 4% of our total revenue, compared with $26.2 million for the year ended December 31, 2014, which represents a 190% year-over-year increase. Adjusted EBITDA from this segment for the year ended December 31, 2015 was ($99.4 million) compared with ($91.8 million) for the year ended December 31, 2014, which represents an 8% year-over-year decrease. Like our core services lines, the businesses comprising our Other Services Segment were negatively impacted by the widespread reduction in drilling, completion and production activity over the course of the year.

With respect to the fourth quarter of 2015, revenue from our Other Services segment was $16.7 million, representing approximately 4% of our total revenue, compared to revenue of $19.7 million for the third quarter of 2015, which represents a 16% decrease quarter over quarter. Fourth quarter Adjusted EBITDA from this segment was ($24.6 million), compared to Adjusted EBITDA of ($26.4 million) for the third quarter of 2015, which represents a 7% sequential increase. Like our core services lines, the businesses comprising our Other Services segment were negatively impacted by the falling rig count and the typical year-end slowdown. In spite of declining activity levels, we were able to sequentially grow revenue within two of our most promising R&T initiatives: directional drilling and artificial lift applications. Additionally, in spite of a more than 15% reduction in revenue from this segment during the fourth quarter, Adjusted EBITDA increased approximately 7% as a result of our continued efforts to cut overhead costs and align our active R&T initiatives with current market conditions.

Operating Overview & Strategy

Our results of operations are driven primarily by deviations in four interrelated, fluctuating variables: (1) the drilling, completion and production activities of our customers, which directly affects the demand for our services; (2) the price we are able to charge for our services, which is driven by the level of demand for our services and 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.

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.

The Baker Hughes U.S. rig count data, which is publicly available on a weekly basis, is widely accepted and used as an indicator of overall exploration and production (“E&P”) company capital spending and resulting oilfield activity levels. Historically, our utilization levels have been highly correlated to U.S. onshore spending by our E&P company customers as a group. Generally, as capital spending by E&P companies 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 E&P companies, 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 E&P companies, 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 lag 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 operating segments primarily based on Adjusted EBITDA because it provides important information to us about the activity and profitability of our lines of business within each 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, regardless of the number of hours worked or whether it generated any revenue during such time. In our Well Support Services operations, we measure activity levels for 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 within each of our core service lines, depending on the type of services 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.

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 exploration and production companies to their drilling, completion and workover budget. 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. Declines and sustained weakness in commodity prices over the course of 2015 and into 2016, and the consequent negative impact on the level of exploration, development and production activity and capital expenditures by our customers, have adversely affected the demand for our services and, absent a significant rebound in commodity prices and corresponding increase in exploration, development and production activity by our customers, are expected to adversely affect demand for our services in the future. This, in turn, negatively impacts our ability to maintain utilization of assets and negotiate pricing at levels generating sufficient margins, especially in our hydraulic fracturing business.

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 and, to a lesser extent, in Western Canada. 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. For example, during 2015 and to date, oil prices reached and remained at their lowest levels since 2009, declining to as low as $26 per barrel, but with highs at $61 per barrel. Gas prices declined in 2009 and have remained depressed relative to historical levels.

Declines or 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. We have experienced a significant increase in each of these customer responses to the current commodity price environment since January 1, 2016. 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 will adversely affect the demand for our services and our financial condition and results of operations.

Competition and Demand for Our Services

Our revenues and earnings are directly affected by changes in utilization and pricing levels for our services, which fluctuate in response to changes in the level of drilling, completion and workover activity by our customers. 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 maintain utilization and pricing for our services or implement price increases. 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.

Our competitors include many large and small energy service companies, including some of the largest integrated energy services companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can, including by reducing prices for services. Our major competitors for our Completion Services include Halliburton, Schlumberger, Baker Hughes, CalFrac Well Services, Trican, Weatherford International, RPC, Inc., Pumpco, a subsidiary of Superior Energy Services, Frac Tech, Basic Energy Services and Archer, as well as a significant number of regional businesses. Our major competitors for our Well Support Services include Halliburton, Schlumberger, Baker Hughes, Key Energy Services, Basic Energy Services, Superior Energy Services, Precision, Forbes, Pioneer, as well as a significant number of 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 like we experienced during 2015 and continue to experience to date. 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. While we must be competitive in our pricing, we believe many of our customers elect to work with us based on the safety, performance and quality of our crews, equipment and services. 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.

Current Market Conditions and Outlook

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 resulted in severe reductions in drilling, completion and production activities. This resulted in a significant decrease in demand for our services, with reductions in customer budgets driving severe utilization declines, and increased competition and pricing pressure to varying degrees across our service lines and operating areas. As our customers reduced their service needs and budgets, we worked with them, including through pricing concessions, when necessary to secure utilization and protect market share across our service lines, while also seeking ways to deliver greater efficiencies and reduce our operating costs. However, our financial and operating results were adversely impacted by the weak activity and pricing environment characterizing this downturn.

In response to challenging market conditions, and also as part of our integration plan in anticipation of the Merger, late in the first quarter of 2015 we began to scale back our operations and align our cost structure with activity levels. We idled equipment, reduced headcount, implemented strict cost control measures and negotiated substantial price reductions with suppliers to lower our operating costs. However, our ability to obtain cost reductions from our third-party suppliers lagged behind the drop in pricing for our services, which further compressed margins. With the Merger closing during the early part of the downturn, we had the impetus to double-down on our efforts to streamline our combined company and to further improve our cost structure, leveraging our greater scale. We stacked unproductive equipment, further reduced head count, including through the elimination of duplicative personnel, closed or consolidated facilities, and implemented other measures to bring our operations and cost-structure in-line with existing activity levels and anticipated instability over the near term.

In the face of challenging headwinds, we successfully completed the integration of Legacy C&J and the C&P business ahead of schedule, which involved a substantial effort across our employee base to integrate the numerous systems and functions in a timely manner. We achieved greater synergies than originally anticipated, and at an accelerated pace. For example, we achieved procurement synergy savings from applying more favorable pricing on key consumables, such as proppant, trucking and chemicals, to our expanded Completion Services operations, and the elimination of duplicative personnel and facilities provided some synergy savings with respect to corporate overhead and administrative expenses. Additionally, through our various R&T initiatives we became more vertically integrated, which has enabled us to continue to reduce our cost structure, creating opportunities to drive revenue and gain market share.

Looking forward, the severity and duration of this downturn remain uncertain and we are preparing for industry conditions to remain extremely challenging through 2016. Activity and pricing levels have declined since the beginning of the year, which will negatively impact our first quarter financial and operating results. We are actively monitoring the market and managing our business in line with demand for services, and we will continue to make adjustments as necessary to effectively respond to the challenging conditions, including further scaling back our strategic initiatives and both core and non-core businesses. We are maintaining an intense focus on lowering our input and labor costs, driving costs savings and controlling expenses. Our top priorities remain to drive revenue by maximizing utilization, improve margins through cost controls, protect and grow market share by focusing on the quality and efficiency of our service execution and ensure we are strategically positioned to capitalize on any future market improvement or compelling opportunities. Although we believe that we are prepared for the challenges that lie ahead, the ultimate impact of the current industry downturn on our company will depend upon various factors, many of which remain beyond our control. 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

The following is a comparison of our results of operations for the year ended December 31, 2015, compared to the year ended December 31, 2014, and a comparison of our results of operations for the year ended December 31, 2014, compared to the year ended December 31, 2013. Our results for the 2015 year include the financial and operating results of Legacy C&J for the entire period and the C&P Business from the Effective Time of the Merger (March 24, 2015) through December 31, 2015. Results for periods prior to March 24, 2015 reflect the financial and operating results of Legacy C&J exclusively, and do not include the financial and operating results of the C&P Business. Accordingly, comparisons of 2015 results to prior years may not be meaningful. In addition to the Merger, we have significantly grown our company since the beginning of 2014 as we

executed our long term growth strategy and demonstrated our commitment to diversify and expand our business. As a result of our efforts, as well as market fluctuations, neither our 2015 nor our 2014 results are directly comparable to prior years.

Furthermore, for the first quarter of 2015, we revised our reportable segments to reflect the change in our operating segments as a result of the Merger. Due to the transformative nature of the Merger, our chief operating decision maker (the “CODM”) changed the way in which the Company is managed, which included a revised segment approach in making performance evaluation and resource allocation decisions. Discrete financial information was created to provide the segment information necessary for the CODM to manage the Company under the revised operating segment structure. The current reportable business segment structure reflects the financial information and reports used by management, including our CODM, to make decisions regarding the Company’s business, including performance evaluation and resource allocation decisions. We have recast the segment information included in this Annual Report to reflect the new reportable segment structure in order to conform to the current year presentation.

Results for the Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

The following table summarizes the change in our results of operations for the year ended December 31, 2015, compared to the year ended December 31, 2014 (in thousands):



	Years Ended December 31,
	2015			2014			$ Change
Revenue	$	1,748,889		$	1,607,944		$	140,945
Costs and expenses:
Direct costs	1,523,116			1,179,227			343,889
Selling, general and administrative expenses	239,775			182,518			57,257
Research and development	16,704			14,327			2,377
Depreciation and amortization	276,353			108,145			168,208
Impairment Expense	791,807			—			791,807
Loss on disposal of assets	(544		)	(17		)	(527		)
Operating income	(1,098,322		)	123,744			(1,222,066		)
Other income (expense):
Interest expense, net	(82,086		)	(9,840		)	(72,246		)
Other income (expense), net	8,773			598			8,175
Total other expenses, net	(73,313		)	(9,242		)	(64,071		)
Income (loss) before income taxes	(1,171,635		)	114,502			(1,286,137		)
Income tax expense (benefit)	(299,093		)	45,679			(344,772		)
Net income (loss)	$	(872,542	)	$	68,823		$	(941,365	)

Revenue

Revenue increased $140.9 million, or 8.8%, for the year ended December 31, 2015, as compared to the year ended December 31, 2014. The increase in revenue was primarily due to our significantly larger asset base and expanded operations as a result of the Merger and the incremental impact of $822.2 million of revenue contributed by the C&P Business, offset by a $681.3 million decrease in revenue from Legacy C&J due to significantly lower utilization and pricing levels across our Completion Services segment resulting from the extremely competitive market environment caused by the continued decline in U.S. onshore drilling and completion activity.

Direct Costs

Direct costs increased $343.9 million, or 29.2%, to $1.5 billion for the year ended December 31, 2015, as compared to $1.2 billion for the year ended December 31, 2014, primarily due to our significantly larger asset base and expanded operations as a result of the Merger, including additional direct costs of $697.6 million from the C&P Business, partially offset by a $353.7 million decrease in direct cost attributable to Legacy C&J.

As a percentage of revenue, direct costs increased to 87.1% for the year ended December 31, 2015, up from 73.3% for the year ended December 31, 2014, primarily due to substantially lower pricing for our services due to competitive market conditions resulting from the rapid decline in commodity prices, partially offset by reductions to our cost structure achieved through our supply chain and procurement synergy savings following the Merger.

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

SG&A increased $57.3 million, or 31.4%, to $239.8 million for the year ended December 31, 2015, as compared to $182.5 million for the year ended December 31, 2014. Excluding an increase of $22.5 million in acquisition-related costs, the remaining increase in SG&A for the year ended December 31, 2015 was primarily driven by a significantly greater employee base as a result of the Merger, partially offset by the implementation of our integration plan following the Merger and market-driven cost control initiatives, including reductions in headcount and facilities.

We also incurred $16.7 million in R&D for the year ended December 31, 2015, as compared to $14.3 million for the corresponding prior year period. We remain committed to investing in key technologies that we lower our cost base for key inputs, enhance synergy savings and improve our operational capabilities and efficiencies. However, as part of our cost control measures, during the latter half of 2015, we scaled back our research and technology division and delayed certain projects.

Depreciation and Amortization Expense ("D&A")

D&A increased $168.2 million, or 155.5%, to $276.4 million for the year ended December 31, 2015 as compared to $108.1 million for the same period in 2014. The increase in D&A was primarily related to our significantly larger asset base as a result of the Merger, as well as the deployment of new equipment in Legacy C&J's core service lines.

Impairment Expense

Impairment expense for the year ended December 31, 2015 was $791.8 million and consisted of $385.0 million of goodwill impairment and $393.1 million of property, plant and equipment ("PP&E") impairment, both related to the Completion Services and Other Services segments, and $13.8 million related to other intangible assets.

Due to the continued downturn in the oil and gas industry, and the resulting further deterioration in demand for our services, we determined that it was necessary to test goodwill for impairment and to test PP&E and intangible assets for recoverability during the third quarter of 2015 and again during the fourth quarter of 2015. As a result, we recorded a non-cash pre-tax charge of $394.2 million related to impairment of goodwill and intangible assets for our Completion Services and Other Services segments for the third quarter of 2015, and we recorded a non-cash pre-tax charge of $393.1 million related to impairment of PP&E from certain asset groups within each of our Completion Services segment and Other Services for the fourth quarter of 2015.

No impairment was incurred for the year ended December 31, 2014.

Interest Expense, net

Interest expense increased $72.2 million, or 734.2%, to $82.1 million for the year ended December 31, 2015 due to higher levels of borrowings, primarily to finance the Merger.

Income Taxes

We recorded an income tax benefit of $299.1 million for the year ended December 31, 2015, at an effective rate of 25.5%, compared to income tax expense of $45.7 million for the year ended December 31, 2014, at an effective rate of 39.9%. The decrease in the effective tax rate is primarily due to a pre-tax loss in the current year, as compared to pre-tax income in the prior year. 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 on the tax rate and the recognition of non-deductible acquisition related costs.

Results for the Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

The following table summarizes the change in our results of operations for the year ended December 31, 2014, when compared to the year ended December 31, 2013 (in thousands):



	Years Ended December 31,
	2014			2013			$ Change
Revenue	$	1,607,944		$	1,070,322		$	537,622
Costs and expenses:
Direct costs	1,179,227			751,468			427,759
Selling, general and administrative expenses	182,518			124,404			58,114
Research and development	14,327			5,005			9,322
Depreciation and amortization	108,145			74,703			33,442
Loss on disposal of assets	(17		)	527			(544		)
Operating income	123,744			114,215			9,529
Other income (expense):
Interest expense, net	(9,840		)	(6,550		)	(3,290		)
Other income (expense), net	598			53			545
Total other expenses, net	(9,242		)	(6,497		)	(2,745		)
Income before income taxes	114,502			107,718			6,784
Income tax expense	45,679			41,313			4,366
Net income	$	68,823		$	66,405		$	2,418

Revenue

Revenue increased $537.6 million, or 50.2%, for the year ended December 31, 2014, as compared to the year ended December 31, 2013. Our Completion Services segment contributed $403.2 million of additional revenue from our hydraulic fracturing services and $129.7 million of additional revenue from our wireline services. The increased revenue for the year ended December 31, 2014 was driven by high activity and service intensity levels, strong operational execution and the deployment of additional equipment across our service lines.

Direct Costs

Direct costs increased $427.8 million, or 56.9%, to $1.2 billion for the year ended December 31, 2014, as compared to $751.5 million for the year ended December 31, 2013. Our Completion Services segment had $408.1 million of additional direct costs primarily from our hydraulic fracturing services and $69.7 million of additional direct costs from our wireline services, in each instance related to a corresponding increase in revenue. As a percentage of revenue, direct costs increased from 70.2% for the year ended December 31, 2013 to 73.3% for the year ended December 31, 2014, primarily due to increased exposure to a highly competitive spot market for our hydraulic fracturing services, as well as increased volumes and costs for proppants and logistics due to a job-mix weighted towards greater service-intensive activity.

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

SG&A increased $58.1 million, or 46.7%, to $182.5 million for the year ended December 31, 2014, as compared to $124.4 million for the year ended December 31, 2013. We also incurred $14.3 million in R&D for the year ended December 31, 2014, as compared to $5.0 million for the year ended December 31, 2013.

Excluding $20.2 million in transaction costs associated primarily with the Transactions, the increases in SG&A and R&D were primarily due to increased costs associated with the continued investment in our strategic initiatives, including service line diversification, vertical integration, technological advancement and international expansion. Inclusive of both SG&A and R&D, our strategic initiatives contributed approximately $39.7 million of additional costs for the year ended December 31, 2014.

Depreciation and Amortization Expense ("D&A")

D&A increased $33.4 million, or 44.8%, to $108.1 million for the year ended December 31, 2014, as compared to $74.7 million for the year ended December 31, 2013. The increase was primarily related to the deployment of new incremental equipment for our hydraulic fracturing, coiled tubing, wireline and pressure pumping service lines.

Interest Expense, net

Interest expense increased $3.3 million, or 50.2%, to $9.8 million for the year ended December 31, 2014, as compared to $6.6 million for the year ended December 31, 2013, due to increased average debt balances.

Income Taxes

We recorded income tax expense of $45.7 million for the year ended December 31, 2014, at an effective rate of 39.9%, compared to $41.3 million for the year ended December 31, 2013, at an effective rate of 38.4%. The increase in the effective tax rate is primarily due to an increase in permanent differences between book and taxable income and foreign losses not benefited in income tax expense.

Liquidity and Capital Resources

Current Financial Condition and Liquidity

As of December 31, 2015, we had a cash balance of approximately $25.9 million, $121.0 million in borrowings outstanding under our Revolving Credit Facility (as defined and discussed below) along with $12.6 million of outstanding letters of credit, and $1.05 billion outstanding under a Term Loan B (as defined and discussed below) comprised of a $570.7 million term loan B-1 and a $481.4 million term loan B-2. We also had $32.0 million in long-term capital lease obligations. The long-term debt balance is net of $52.4 million of original issue discount on the Term Loan B. As of December 31, 2015, the Revolving Credit Facility had $166.4 million available for borrowing based on $300.0 million of Revolver availability in accordance with the Collateral Coverage Covenant (as defined and discussed below) under the Amended Credit Agreement. We generated $103.0 million of cash from operations during the twelve months ended December 31, 2015. Please see “Financial Condition and Cash Flows” below for information about net cash provided by or used in our operating, investing and financing activities.

As of February 23, 2016, we had a cash balance of approximately $93.6 million and $251.0 million in borrowings outstanding under our Revolving Credit Facility with $36.4 million available for additional borrowing based on $300.0 million of Revolver availability in accordance with the Collateral Coverage Covenant. While we do not have an immediate need for these funds to continue operations, management believes it prudent to ensure direct access to this capital over the course of 2016 in order to ensure the Company is in the best possible position to manage the current market environment. As a result, absent the issuance of additional securities, alternative financing arrangements or the repayment of outstanding borrowings under our Revolving Credit Facility, our operations for the foreseeable future will be funded from cash flow from operations, cash on hand and the remaining $36.4 million of availability that may be drawn in ordinary course from time to time. The additional draws of $130.0 million on our Revolving Credit Facility since December 31, 2015 will result in approximately $1.1 million of additional interest expense for the first quarter of 2016, which may increase net loss and decrease cash flow from operations.

On September 29, 2015, we entered into the Amendments (as defined and discussed below) to our Credit Agreement that, among other things: (1) reduced the Revolver commitment from $600.0 million to $400.0 million, provided, however, that availability is subject to the newly implemented Collateral Coverage Covenant (herein so called), which limits availability to the greater of (i) $300.0 million and (ii) an amount derived from 80% of Eligible Receivables (as defined and discussed below) and 50% of Eligible Inventory (as defined and discussed below); (2) temporarily suspends the quarterly Total Leverage Ratio (as defined and discussed below) and Interest Coverage Ratio (as defined and discussed below) covenants set forth in the Credit Agreement, commencing with the fiscal quarter ending September 30, 2015 through the fiscal quarter ending June 30, 2017; (3) provides that upon reinstatement of the Total Leverage Ratio and Interest Coverage Ratio, the required test levels initially will be more permissive than those in effect prior to the Amendments, and will gradually adjust to those prior levels over the subsequent fiscal quarters; (4) provides for new financial covenants that will apply in lieu of the Total Leverage Ratio and Interest Coverage Ratio, including a quarterly Minimum EBITDA Target covenant (as defined and discussed below), commencing with the quarter ended September 30, 2015 and running through the quarter ending June 30, 2017, based on a negotiated EBITDA test; and (5) sets quarterly limitations on capital expenditures for the quarter ending December 31, 2015, and annual limitations on capital expenditures for the four fiscal quarter periods ending December 31, 2016 through June 30, 2017. Please see “ - Description of Our Credit Agreement” below and Note 2 - Long-Term Debt and Capital Lease Obligations in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information about the Credit Agreement.

As of December 31, 2015, absent the Amendments, we would not have been in compliance with the Total Leverage Ratio or the Interest Coverage Ratio. However, as of December 31, 2015 we are in compliance with the financial covenants required by the Amended Credit Agreement. If our activity and/or pricing levels remain at current levels or do not improve, we are at risk of not being able to comply with our minimum EBITDA Target covenant in future periods.

Capital expenditures totaled $166.3 million for the year ended December 31, 2015, primarily relating to maintenance of our existing equipment. In response to persistently challenging industry conditions, we have significantly scaled back our 2016 capital expenditure plan and capital expenditures for 2016 are expected to range from $75 million to $100 million. These expenditures are expected to be funded from cash flows from operations and cash on hand (including from our recent draws under our Revolver).

Our current focus is on preserving liquidity by lowering our operating expenses, controlling costs, reducing capital expenditures and maximizing collection of receivables. Based on our existing operating performance, 2016 planned capital expenditures, and ongoing cost reduction measures, we currently believe that our cash flows from operations and existing capital, coupled with cash on hand and borrowings available under our Revolving Credit Facility, will be sufficient to meet our operational and capital expenditure requirements over the next twelve months. Our ability to access additional sources of financing will be dependent on our operating cash flows and demand for our services, which could be negatively impacted due to the extreme volatility of commodity prices and declines in capital and debt markets. Please see “ – Description of Our Credit Agreement” below for additional information about our Revolving Credit Facility as amended by the Amendments; please also see “Risk Factors” in Part I, Item 1A of this Annual Report for a discussion of potential risks associated with our existing indebtedness and financial and restrictive covenant structure in light of current market conditions.

Sources of Liquidity and Capital Resources

Our primary sources of liquidity include cash on hand, cash flows from operations and borrowings under senior secured debt facilities, including our Revolving Credit Facility. Historically, our primary uses of capital were for the growth of our Company, including the Merger and other strategic acquisitions that complement and enhance our business, the purchase and maintenance of equipment for our core service lines, geographic expansion (both domestic and international), and our ongoing strategic initiatives, most notably including the advancement of our research and technology capabilities and vertical integration. Our capital expenditures, maintenance costs and other expenses have increased substantially over the last few years in line with the significant growth we have achieved and the ongoing execution of our long-term growth strategy.

As a result of the Merger, we have improved operational scale, as well as a greater combined lending base, coupled with the expected benefit of a lower cost of capital. However, like our competitors, our operational and financial results have been significantly impacted by the current downturn, which in turn impacts our liquidity and financial flexibility, as well as our ability to continue to comply with the financial covenants contained in the Credit Agreement. Anticipating that we would not be able to comply with the Total Leverage Ratio or the Interest Coverage Ratio, on September 29, 2015, we entered into the Amendments to the Credit Agreement to obtain relief from those financial covenants. Accordingly, as of December 31, 2015, we are in compliance with the financial covenants required by the Amended Credit Agreement. We believe the Amendments were a positive development for the Company, as we believe they provide us with the flexibility to continue to work through this challenging time for our industry. However, in the event activity and/or pricing levels remain at current levels or do not improve, we may be unable to continue comply with these financial covenants in future periods. Notwithstanding the forgoing, the Credit Agreement contains customary restrictive covenants and financial covenants that may limit our ability to engage in activities that may be in our long-term best interests, including limitations on our ability to create, incur, assume or suffer to exist liens or indebtedness, sell or otherwise dispose of assets, make certain restricted payments and investments, enter into transactions with affiliates and prepay certain indebtedness. Please see “ – Description of Our Credit Agreement” below and Note 2 – Long-Term Debt and Capital Lease Obligations in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information about our Credit Agreement, including the Amendments. Please also see “Risk Factors” in Part I, Item 1A of this Annual Report.

Liquidity Outlook and Future Capital Requirements

The energy services business is capital-intensive, requiring significant investment to maintain, upgrade and purchase equipment to meet our customers’ needs and industry demand. To date, our capital requirements have consisted primarily of, and we anticipate, over the long-term, will continue to be:


•	growth capital expenditures, which are capital expenditures made to acquire additional equipment and other assets, increase our service lines, expand geographically or advance other strategic initiatives for the purpose of growing our business; and


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

Additionally, in the near term, we anticipate our capital requirements will consist almost entirely of capital expenditures related to our existing equipment, such as maintenance and other activities to extend the useful life of partially or fully depreciated assets.

The successful execution of our long-term growth strategy depends on our ability to generate sufficient cash flows and /or raise additional capital as needed. Historically, we have been able to generate solid cash flows in spite of challenging market conditions and our free cash flow and balance sheet allowed us to be flexible with our approach to organic growth and acquisition opportunities. Our ability to fund future growth depends on our performance, which is impacted by factors beyond our control, including financial, business, economic and other factors, such as potential changes in customer preferences and pressure from competitors. Our current level of indebtedness could limit our ability to finance future growth and adversely affect our operations and financial condition. Additionally, the financial and other restrictive covenant obligations contained in the Credit Agreement may restrict our operational flexibility and limit our ability to create, incur, assume or suffer to exist liens or indebtedness, sell or otherwise dispose of their assets, make certain restricted payments and investments and prepay certain indebtedness.

As of December 31, 2015, absent the Amendments, we would not have been in compliance with the Total Leverage Ratio or the Interest Coverage Ratio covenants contained in the Credit Agreement. Anticipating that we would not be able to comply with the Total Leverage Ratio or the Interest Coverage Ratio, on September 29, 2015, we entered into the Amendments to the Credit Agreement to obtain relief from those financial covenants. Accordingly, as of December 31, 2015, we are in compliance with the financial covenants required by the Amended Credit Agreement. However, in the event activity and/or pricing for our services remains at current levels or do not improve, we may be unable to continue comply with these financial covenants in future periods. Please see “ – Description of Our Credit Agreement” below and Note 2 – Long-Term Debt and Capital Lease Obligations in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report for additional information about the Credit Agreement; please see “Risk Factors” in Part I, Item 1A of this Annual Report for a discussion of potential risks associated with our existing indebtedness and financial covenant structure in light of current market condition.

Over the past two years, we have significantly invested in growing our core service lines through the expansion of our assets, customer base and geographic reach, both domestically and internationally. We have also significantly invested in advancing our ongoing strategic initiatives designed to strengthen, expand and diversify our business, notably including service line diversification, vertical integration and technological advancement. Our continued investments in international expansion and our strategic initiatives have resulted in increased capital expenditures and costs, and as we execute our long-term growth strategy and further develop our strategic initiatives, we anticipate that our costs and expenses will continue to increase. To date, neither our international operations nor our strategic initiatives have contributed significant third-party revenue; however, we expect that they will contribute meaningful third-party revenue over the long term.

Entering 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. This resulted in increased competition and pricing pressure to varying degrees across our service lines and operating areas. Activity levels across our operations have remained depressed throughout 2015. Our 2015 financial and operating performance was negatively impacted by the continued weakness in demand for our services, with reductions in customer budgets and drilling and completion activity driving severe utilization declines and pricing pressure. Although the severity and duration of this downturn remains uncertain, absent a significant recovery in commodity prices, we expect that activity and pricing levels will remain depressed, which will negatively impact our financial and operating results over the near term, in spite of the aggressive actions we have taken, and are taking, to scale back our operations and align our cost structure with the highly competitive market environment.

Given the challenging market conditions currently facing our industry, we significantly scaled back our 2016 capital expenditure plan to focus on capital expenditures related to our existing equipment, including maintenance and other activities purposed to extend the useful life of our assets. Based on our existing operating performance, 2016 planned capital expenditures and ongoing cost reduction measures, we currently believe that our cash flows from operations and existing capital, coupled with cash on hand and borrowings available under our Revolving Credit Facility, will be sufficient to meet our operational and capital expenditure requirements over the next twelve months.

Given the investments we have made in expanding our service lines, including through investing in new equipment, coupled with our vertically integrated equipment manufacturing and repair business and research and technology capabilities, we believe that we have built a strong platform that will enable us to perform at the highest level through this current downturn and when the market recovers. With respect to our strategic initiatives, we believe that the strategic investments in vertical integration and our research and technology capabilities that we have made, and our efforts to lower our cost base for key

inputs and improve our operational capabilities and efficiencies, will help us manage through this down-cycle. Several of our research and technology initiatives are now generating monthly cost savings to our Completion Services operations and are also helping to generate revenue. Although the financial benefits are still minimal at this time, we believe that these strategic projects will deliver meaningful cost savings to us over the long term. Even as we seek to reduce costs, we remain committed to investing in key technologies that lower our cost base for key inputs, enhance synergy savings and improve our operational capabilities and efficiencies. However, we will continue to monitor the economic environment and demand for our services and adjust our business strategy as necessary to effectively respond to the market. If this current industry downturn persists or worsens, we are prepared to delay further investment in these projects in line with any sustained market weakness and to take the necessary steps to further protect our company and maximize value for all of our shareholders.

Financial Condition and Cash Flows

The net cash provided by or used in our operating, investing and financing activities is summarized below (in thousands):



	Years Ended December 31,
	2015			2014			2013
Cash flow provided by (used in):
Operating activities	$	103,005		$	181,837		$	181,101
Investing activities	(825,156		)	(343,412		)	(165,295		)
Financing activities	734,126			157,178			(15,834		)
Effect of exchange rate on cash	3,908			—			—
Decrease (increase) in cash and cash equivalents	$	15,883		$	(4,397	)	$	(28	)

Cash Provided by Operating Activities

Net cash provided by operating activities decreased $78.8 million for the year ended December 31, 2015 as compared to the corresponding period in 2014. The decrease in operating cash flow was primarily due to (a) the decline in net income during the year ended December 31, 2015, after excluding the effects of changes in non-cash items, (b) cash used to satisfy obligations related to accounts payable and accrued liabilities assumed in the C&P Business acquisition and (c) incremental cash used to pay down accounts payable, partially offset by positive changes which included an increase in cash provided from the collection of accounts receivable assumed in the C&P Business acquisition and operating assets and liabilities related to normal fluctuations in the timing of cash collections and cash requirements.

Net cash provided by operating activities was $0.7 million higher for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The increase in operating cash flow was primarily due to the increase in net income during 2014, after excluding the effects of changes in non-cash items, partially offset by changes in operating assets and liabilities which included (a) incremental cash used to satisfy inventory levels primarily due to vertical integration efforts and (b) incremental cash used from changes in other operating assets and liabilities related to our growth and from normal fluctuations due to the timing of cash collections and cash requirements.

Cash Flows Used in Investing Activities

Net cash used in investing activities increased $481.7 million for the year ended December 31, 2015 as compared to the corresponding period in 2014. This increase was primarily due to the cash consideration of $693.5 million paid at the closing of the Merger for the acquisition of the C&P Business, partially offset by a $43.4 million purchase price reduction for the C&P Business related to a working capital adjustment and a decline in capital expenditure purchases as a result of the downturn in the oil and gas industry.

Net cash used in investing activities increased $178.1 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. This increase was due to a $155.8 million increase in capital expenditures primarily related to new equipment additions in our Stimulation and Well Intervention Services and Wireline Services segments, as well as a $33.2 million for the Tiger Acquisition.

Cash Flows Provided by (Used in) Financing Activities

Net cash provided by financing activities increased $576.9 million for the year ended December 31, 2015 as compared to the corresponding period in 2014. The increase is primarily related to proceeds received from our Credit Agreement to fund the cash consideration portion of the acquisition of the C&P Business at the closing of the Merger as well as to pay off the long-term debt of Legacy C&J.

Net cash provided by financing activities was $157.2 million for the year ended December 31, 2014 as compared to net cash used in financing activities of $15.8 million for the same period in 2013. Net cash provided by financing activities increased $173.0 million primarily due to net borrowings from our credit facility to fund increased capital expenditures related to new equipment, the Tiger Acquisition, and transaction costs associated with the Pending Nabors Transaction.

Description of Our Credit Agreement

In connection with the closing of the Merger, we entered into a new credit agreement, dated as of March 24, 2015 (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 in an aggregate principal amount of $1.66 billion, consisting of (a) a $600.0 million Revolving Credit Facility and (b) a Term Loan B in the aggregate principal amount of $1.06 billion.

On September 29, 2015, we entered into a waiver and second amendment (the "Waiver and Second Amendment") and a third amendment (the "Third Amendment" and, together with the Waiver and Second Amendment, the "Amendments") to the Original Credit Agreement (as amended by the Amendments described below, the "Amended Credit Agreement" or the "Credit Agreement") intended to provide the Company with increased financial flexibility through the third quarter of 2018. The Waiver and Second Amendment, among other things, suspends the quarterly Total Leverage Ratio and Interest Coverage Ratio covenants set forth in the Original Credit Agreement commencing with the fiscal quarter ending September 30, 2015 and running through the fiscal quarter ending June 30, 2017. Upon reinstatement of these covenants as of the quarter ending September 30, 2017, the required levels initially will be more permissive than those in effect prior to the Waiver and Second Amendment, and will gradually adjust to those prior levels over the subsequent fiscal quarters.

The Waiver and Second Amendment also provides for new financial covenants that will apply in lieu of the quarterly Total Leverage Ratio and Interest Coverage Ratio previously in effect, including the following:


•	a quarterly minimum EBITDA covenant, commencing with the quarter ended September 30, 2015 and running through the quarter ending June 30, 2017, based on a negotiated EBITDA test ("Minimum EBITDA covenant");

•

a collateral coverage covenant ("Collateral Coverage covenant") commencing at the closing of the Waiver and Second Amendment and running through the quarter ending March 31, 2018, which will limit outstanding Revolver borrowings and letters of credit to the greater of (i) $300.0 million and (ii) an amount derived from 80% of Eligible Receivables (as defined in the Waiver and Second Amendment) and 50% of Eligible Inventory (as defined in the Waiver and Second Amendment) (subject to the reduced maximum Revolver borrowing capacity described below); and


•	a quarterly limitation on capital expenditures for the quarter ending December 31, 2015, and annual limitations on capital expenditures for the four fiscal quarter periods ending December 31, 2016 through June 30, 2017

In summary, the Credit Agreement contains financial covenants applicable to the Revolver and the Five-Year Term Loan, which include: (i) a maximum Total Leverage Ratio of 5.50:1.00 for the fiscal quarter ending September 30, 2017, 5.00:1.00 for the fiscal quarter ending December 31, 2017, 4.50:1.00 for the fiscal quarter ending March 31, 2018, 4.25:1.00 for the fiscal quarter ending June 30, 2018 and 4.00:1.00 for each fiscal quarter thereafter; (ii) a minimum quarterly ratio of consolidated EBITDA of C&J and its subsidiaries to consolidated interest expense of C&J and its subsidiaries ("Interest Expense Ratio") of 2.50:1.00 for the fiscal quarters ending September 30, 2017 and December 31, 2017, 2.75:1.00 for the fiscal quarter ending March 31, 2018 and 3.00:1.00 for each fiscal quarter thereafter; and (iii) starting September 30, 2015 and until the fiscal quarter ending June, 30, 2017, a Minimum Cumulative Consolidated EBITDA covenant as follows (in thousands):



	Minimum Cumulative Consolidated EBITDA ⁽¹⁾	Cumulative Cushion Amount
Three months ended September 30, 2015	$(15,000)	$10,000
Three months ended December 31, 2015	$10,000	$20,000
Six months ended March 31, 2016	$28,000	$40,000
Nine months ended June 30, 2016	$63,000	$60,000
Twelve months ended September 30, 2016	$121,000	$60,000
Twelve months ended December 31, 2016	$115,000	None
Twelve months ended March 31, 2017	$165,000	None
Twelve months ended June 30, 2017	$205,000	None

(1) Minimum Cumulative Consolidated EBITDA is defined as total earnings (loss) before net interest expense, income taxes, depreciation and amortization, other income (expense), and net gain or loss on disposal of assets, and excludes, among other things, share-based compensation expense, acquisition-related costs, and non-routine items.

The Company may use some or all of the “Cumulative Cushion Amount” set forth above to increase the Cumulative Consolidated EBITDA for the specified given period for purposes of satisfying the Minimum Cumulative Consolidated EBITDA test applicable to such period. In the event the Company utilizes only some of the Cumulative Cushion Amount for such period, any used amount for such period will reduce the Cumulative Cushion Amount specified for any future period.

The effectiveness of the above-referenced covenant suspension is also subject to certain conditions subsequent that, among other things, will reduce our capacity to make investments and restricted payments through the quarter ending December 31, 2017.

Pursuant to the Third Amendment, the revolving lenders agreed to replace the existing revolving facility with a new revolving facility having a revised pricing grid that increases the applicable rate on revolving borrowings by (i) 50 basis points in the event that C&J’s most recently reported Total Leverage Ratio is greater than 4.0 to 1.0 and less than or equal to 4.5 to 1.0 and (ii) 100 basis points in the event that C&J’s most recently reported Total Leverage Ratio is greater than 4.5 to 1.0.

In connection with the Waiver and Second Amendment and the Third Amendment, the Company also reduced maximum borrowing capacity under the revolving facility pursuant to the Credit Agreement from $600.0 million to $400.0 million.

The borrowers under the Revolving Credit Facility are C&J, Luxco and CJ Holding Co. The borrower under the Term Loan B Facility is CJ Holding Co. All obligations under the Credit Agreement are guaranteed by the Company’s wholly-owned domestic subsidiaries, other than immaterial subsidiaries.

Borrowings under the Revolving Credit Facility will mature on March 24, 2020 (except that if any Five-Year Term Loans (described below) have not been repaid prior to September 24, 2019, the Revolving Credit Facility will mature on September 24, 2019). The Term Loan B Facility is comprised of two tranches: a tranche consisting of $572.1 million in aggregate principal amount of term loans as of September 30, 2015 maturing on March 24, 2020 (the “Five-Year Term Loans”) and a tranche consisting of a $482.6 million in aggregate principal amount of term loans as of September 30, 2015 maturing on March 24, 2022 (the “Seven-Year Term Loans”).Borrowings under the Revolving Credit Facility are non-amortizing. The Term Loan B Facility requires 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 bear interest based on, at the option of the borrower, the London Interbank Offered Rate (“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 requires that the borrowers pay a commitment fee equal to a percentage of unused commitments which varies based on the Total Leverage Ratio.

Five-Year Term Loans outstanding under the Term Loan B Facility bear 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 5.5%, or an alternative base rate, plus a margin of 4.5%. Seven-Year Term Loans outstanding under the Term Loan B Facility bear 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 Term Loan B Facility also contains ‘most favored nation’ pricing protection requiring that if the effective yield (giving effect to, among other things, consent fees paid to the lenders) of the Five-Year Term Loans increases by more than 50 basis points, the effective yield of the Seven-Year Term Loans must increase by the same amount less 50 basis points.

The alternative base rate is equal to the highest of (i) the Administrative Agent’s prime rate, (ii) the Federal Funds Effective Rate plus 0.50% and (iii) LIBOR plus 1.0%.

Subject to certain conditions and limitations, the Credit Agreement permits the borrowers to increase the aggregate commitments under the Revolving Credit Facility in a total principal amount of up to $100.0 million.

The Revolving Credit Facility is permitted to be prepaid from time to time without premium or penalty. Five-Year Term Loans are subject to a prepayment premium of 4% for any voluntary prepayments made on or prior to March 24, 2016 and no prepayment premium thereafter. Seven-Year Term Loans will be subject to a prepayment premium of 5% for any voluntary prepayments made on or prior to March 24, 2017 and no prepayment premium thereafter.

Subject to certain conditions and exceptions, the Term Loan B Facility is required to be prepaid under particular circumstances, including (i) in the event that C&J and its subsidiaries generate Excess Cash Flow (as defined in the Credit Agreement) in any fiscal year, in an amount equal to 50% of the Excess Cash Flow for such fiscal year if the Total Leverage Ratio as of the end of such fiscal year is 3.25:1.00 or greater, (ii) in the event of a sale or other disposition of property by C&J or its subsidiaries, in an amount equal to 100% of the net proceeds of such sale or disposition, subject to customary reinvestment rights and other exceptions, and (iii) in the event of an incurrence of debt not permitted under the Credit Agreement, in an amount equal to 100% of the net proceeds of such debt.

The Credit Agreement contains customary restrictive covenants (in each case, subject to exceptions) that limit, among other things, our ability to create, incur, assume or suffer to exist liens or indebtedness, sell or otherwise dispose of their assets, make certain restricted payments and investments, enter into transactions with affiliates, make capital expenditures and prepay certain indebtedness. lease see “Risk Factors” in Part I, Item 1A of this Annual Report for a discussion of potential risks associated with our financial and restrictive covenant structure.

Contractual Obligations

The following table summarizes our contractual cash obligations as of December 31, 2015 (in thousands):



Contractual Obligation	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Revolving Credit Facility⁽¹⁾	$	138,985	$	4,641	$	9,263	$	125,081	$	—
Term Loan B Facility⁽²⁾	1,422,232		83,454		164,302		676,463		498,013
Capital leases⁽³⁾	40,060		3,734		7,269		7,672		21,385
Operating leases	27,837		9,008		8,612		4,147		6,070
Inventory and materials⁽⁴⁾	102,919		33,663		62,880		6,376		—
Service equipment and other capital expenditures	2,064		2,064		—		—		—
Total	$	1,734,097	$	136,564	$	252,326	$	819,739	$	525,468


⁽¹⁾	Includes estimated interest costs at an interest rate of 2.7% along with related charges.


⁽²⁾	Includes estimated interest costs on two term loan tranches at an interest rate of 6.5% and 7.25%.


⁽³⁾	Capital lease amounts include $5.2 million in interest payments.


⁽⁴⁾	Primarily related to sand contract purchase commitments.

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, 2015.

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 are recorded 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 life of the equipment is extended. 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.

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 services, hydraulic fracturing, coiled tubing, wireline, pumpdown, directional drilling, cementing, artificial lift applications, international coiled tubing, equipment manufacturing and repair services, specialty chemicals and data acquisition and control instruments provider service lines as well as the vertically integrated research and technology service line. If the estimated undiscounted future net cash flows for a given asset group is less than the carrying amount of the related assets, an impairment loss is determined by comparing the estimated fair value with the carrying value of the related assets. The impairment loss is then allocated across the asset group's major classifications.

Goodwill, Indefinite-Lived Intangible Assets and Definite-Lived Intangible Assets. Goodwill is allocated to our three reporting units: Completion Services, Well Support Services and Other Services, all of which are consistent with the presentation of our three reportable segments. 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. These intangibles are reviewed for impairment when events or changes in circumstances (a triggering event) indicate that the asset may have a net book value in excess of recoverable value. In these cases, we perform a recoverability test on its definite-lived intangible assets by comparing the estimated future net undiscounted cash flows expected to be generated from the use of the asset to the carrying amount of the asset for recoverability. If the estimated undiscounted cash flows exceed the carrying amount of the asset, 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 asset, the asset is not recoverable and the amount of impairment must be determined by fair valuing the asset.

Mergers and Acquisitions. In accordance with accounting guidance for business combinations, we allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values. We typically engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as trade names and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, up to one year after the acquisition closing date as we obtain more information regarding asset valuations and liabilities assumed.

Our purchase price allocation methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques, including discounted cash flows and market multiple analysis. Unanticipated events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies. If actual results are materially different than the assumptions we used to determine fair value of the assets and liabilities acquired through a business combination, it is possible that adjustments to the carrying values of such assets and liabilities will have an impact on our net earnings.

See “Note 10 – 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

written that includes charges for the service 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 which 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 Revenue. Through its cased-hole wireline service line, the Company provides cased-hole wireline logging, perforating, pressure pumping, 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.

Coiled Tubing and Other Stimulation Services Revenue. Through its coiled tubing service line, the Company provides a range of coiled tubing and other well stimulation services, including nitrogen and pressure pumping services, 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.

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 hydraulic 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.

In addition, ancillary to coiled tubing and other stimulation services revenue, the Company generates revenue from stimulation fluids, nitrogen, coiled tubing materials and other consumables used during those processes.

Well Support Services Segment

Rig Services Revenue. Through its rig service line, the Company primarily provides workover and well servicing rigs that are involved in routine repair and maintenance, completions, re-drilling and plug and abandonment operations. These services are provided on an hourly basis at prices that approximate 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.

Fluids Management Services Revenue. Through its fluids management service line, the Company primarily provides transportation, storage 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.

Other Services Segment

Revenue within the Other Services Segment is generated from certain of the Company's smaller service lines and divisions, specifically directional drilling services, cementing services, equipment manufacturing and repair services, which includes the sale of oilfield parts and supplies, and the blending and sale of specialty chemicals used in completion and production services. Additionally, the Company manages several of its vertically integrated businesses through its research and technology division, which is included within the Other Services Segment.

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 to the customer’s satisfaction, a field ticket is written that includes charges for the service performed.

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 equipment manufacturing and repair services, specialty chemicals provider, data acquisition and control instruments provider and artificial lift applications provider, 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.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are 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, 2015 and 2014, the allowance for doubtful accounts totaled $7.9 million and $2.2 million, respectively. Bad debt expense of $8.1 million, $0.7 million and $0.7 million was included in direct costs on the consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013, 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 shares on the NYSE on the grant date, and we value option grants based on the grant date fair value by using the Black-Scholes option-pricing model, which requires the use of highly 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 we operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of our annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when we recognize income tax expenses and benefits.

We account for income taxes utilizing the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying

amounts of existing assets and liabilities and their respective tax bases. 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 of 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 some portion or all of the deferred tax assets will not be realized.

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% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. We will record income tax related interest and penalties, if applicable, as a component of the provision for income tax expense.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers ("ASU 2015-14"), which deferred the effective date of ASU 2014-09 for all entities by one year and is effective for the Company's fiscal year beginning January 1, 2018. ASU 2015-14 permits the use of either the retrospective or cumulative effect transition method. We have not yet selected a transition method nor has the effect of the standard on ongoing financial reporting been determined.

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. For public entities, ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. ASU 2015-03 is to be applied on a retrospective basis and represents a change in accounting principle. In addition, in August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ("ASU 2015-15"). ASU 2015-15 clarifies the guidance in ASU 2015-03 regarding presentation and subsequent measurement of debt issuance costs related to line-of-credit arrangements. The SEC Staff announced they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We do not expect the adoption of these standards to have a material effect 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. The guidance will require prospective application at the beginning of the Company's first quarter of fiscal 2018, but permits adoption in an earlier period. We are currently evaluating the impact, if any, of adopting this new accounting standard on our results of operations and financial position.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments ("ASU 2015-16"). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The acquirer must record, in the same period's financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. ASU 2015-16 is effective for the Company's fiscal year beginning January 1, 2016. We are currently evaluating the impact, if any, of adopting this new accounting standard on our results of operations and financial position.

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 is required to adopt this ASU for years beginning after December 15, 2016, with early adoption permitted, and the guidance may be applied either prospectively or retrospectively. We do not expect this ASU to have a material 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, 2015, 2014 and 2013. 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 Credit Facility. The impact of a 1% increase in interest rates on our outstanding debt as of December 31, 2015 and 2014 would have resulted in an increase in interest expense and a corresponding decrease in net income of approximately $4.7 million and $3.2 million, respectively.

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	76
Reports of Independent Registered Public Accounting Firms	77
Consolidated Balance Sheets as of December 31, 2015 and 2014	80
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013	81
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013	82
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013	83
Notes to Consolidated Financial Statements	84

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, 2015. 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, 2015.

Management’s assessment of the Company’s internal control over financial reporting as of December 31, 2015 excluded the internal control over financial reporting of Nabors Industries Ltd.'s completions and production services business (the "C&P Business"), which was merged with C&J Energy Services, Inc. on March 24, 2015. The C&P Business represented approximately 44.7% of consolidated revenues and 41.8% of consolidated total assets as of December 31, 2015. The acquisition of ESP Completion Technologies LLC ("ESP") on May 18, 2015, was also excluded from management's assessment as of December 31, 2015. ESP represented approximately 0.3% of consolidated revenues and 0.8% of consolidated total assets as of December 31, 2015.

The Company’s internal control over financial reporting as of December 31, 2015 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears herein.




/s/ Joshua E. Comstock	/s/ Randall C. McMullen, Jr.	/s/ Mark C. Cashiola
Joshua E. Comstock Chairman and Chief Executive Officer (Principal Executive Officer)	Randall C. McMullen, Jr. President and Chief Financial Officer (Principal Financial Officer)	Mark C. Cashiola Vice President and Chief Accounting Officer (Principal Accounting Officer)

February 26, 2016

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

C&J Energy Services Ltd.:

We have audited the accompanying consolidated balance sheets of C&J Energy Services Ltd. and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2015. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of C&J Energy Services Ltd. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2015, 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), C&J Energy Services Ltd.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. This report contains an explanatory paragraph stating that C&J Energy Services Ltd acquired Nabors Completion and Production Services (NCPS) and ESP Completion Technologies, LLC (ESPCT) during 2015 and management excluded from its assessment of the effectiveness of C&J Energy Services Ltd.’s internal control over financial reporting as of December 31, 2015, NCPS and ESPCT’s internal control over financial reporting associated with 44.7% and 0.3%, respectively, of consolidated revenues and 41.8% and 0.8%, respectively, of consolidated total assets of C&J Energy Services Ltd. as of and for the year ended December 31, 2015. Our audit of internal control over financial reporting of C&J Energy Services Ltd. also excluded an evaluation of the internal control over financial reporting of NCPS and ESPCT.

/s/ KPMG LLP

Houston, Texas

February 26, 2016

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

C&J Energy Services Ltd.:

We have audited C&J Energy Services Ltd.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). C&J Energy Services Ltd.’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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 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.

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.

In our opinion, C&J Energy Services Ltd. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

C&J Energy Services Ltd. acquired Nabors Completion and Production Services (NCPS) and ESP Completion Technologies, LLC (ESPCT) during 2015, and management excluded from its assessment of the effectiveness of C&J Energy Services Ltd.’s internal control over financial reporting as of December 31, 2015, NCPS and ESPCT’s internal control over financial reporting associated with 44.7% and 0.3%, respectively, of consolidated revenues and 41.8% and 0.8%, respectively, of consolidated total assets of C&J Energy Services Ltd. as of and for the year ended December 31, 2015. Our audit of internal control over financial reporting of C&J Energy Services Ltd. also excluded an evaluation of the internal control over financial reporting of NCPS and ESPCT.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of C&J Energy Services Ltd. and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2015 and our report dated February 26, 2016 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 26, 2016

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

C&J Energy Services, Inc.

We have audited the accompanying consolidated statements of operations, changes in shareholders’ equity and cash flows of C&J Energy Services, Inc. (a Delaware corporation) and subsidiaries (collectively, the “Company”) for the year ended December 31, 2013. 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 audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of C&J Energy Services, Inc. and subsidiaries operations and their cash flows for the year ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

February 26, 2014, except with respect to Note 11, as to which the date is July 15, 2015

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share data)



	As of December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	25,900		$	10,017
Accounts receivable, net of allowance of $7,917 at December 31, 2015 and $2,210 at December 31, 2014	274,691			290,767
Inventories, net	102,257			122,172
Prepaid and other current assets	72,560			29,525
Deferred tax assets	9,035			8,106
Total current assets	484,443			460,587
Property, plant and equipment, net	1,210,441			783,302
Other assets:
Goodwill	307,677			219,953
Intangible assets, net	147,861			129,468
Deferred financing costs, net of accumulated amortization of $10,532 at December 31, 2015 and $3,662 at December 31, 2014	48,309			3,786
Other noncurrent assets	34,175			15,650
Total assets	$	2,232,906		$	1,612,746
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	213,065		$	229,191
Payroll and related costs	10,335			16,047
Accrued expenses	52,250			30,794
Current portion of long-term debt and capital lease obligations	13,433			3,873
Other current liabilities	1,785			4,926
Total current liabilities	290,868			284,831
Deferred tax liabilities	149,151			193,340
Long-term debt and capital lease obligations, net of original issue discount of $52,413 at December 31, 2015	1,142,077			349,875
Other long-term liabilities	18,167			2,848
Total liabilities	1,600,263			830,894
Commitments and contingencies
Shareholders’ equity
Common shares, par value of $0.01, 750,000,000 shares authorized, 120,420,120 issued and outstanding at December 31, 2015 and 100,000,000 shares authorized, 55,333,392 issued and outstanding at December 31, 2014	1,204			553
Additional paid-in capital	997,766			271,104
Accumulated other comprehensive loss	(4,025		)	(45		)
Retained earnings (deficit)	(362,302		)	510,240
Total shareholders’ equity	632,643			781,852
Total liabilities and shareholders’ equity	$	2,232,906		$	1,612,746

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands, except per share data)



	Years Ended December 31,
	2015			2014			2013
Revenue	$	1,748,889		$	1,607,944		$	1,070,322
Costs and expenses:
Direct costs	1,523,116			1,179,227			751,468
Selling, general and administrative expenses	239,775			182,518			124,404
Research and development	16,704			14,327			5,005
Depreciation and amortization	276,353			108,145			74,703
Impairment expense	791,807			—			—
(Gain) loss on disposal of assets	(544		)	(17		)	527
Operating income (loss)	(1,098,322		)	123,744			114,215
Other income (expense):
Interest expense, net	(82,086		)	(9,840		)	(6,550		)
Other income (expense), net	8,773			598			53
Total other income (expense)	(73,313		)	(9,242		)	(6,497		)
Income (loss) before income taxes	(1,171,635		)	114,502			107,718
Income tax expense (benefit)	(299,093		)	45,679			41,313
Net income (loss)	$	(872,542	)	$	68,823		$	66,405
Net income (loss) per common share:
Basic	$	(8.48	)	$	1.28		$	1.25
Diluted	$	(8.48	)	$	1.22		$	1.20
Weighted average common shares outstanding:
Basic	102,853			53,838			53,038
Diluted	102,853			56,513			55,367

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

(In thousands)



	Years Ended December 31,
	2015			2014			2013
Net income (loss)	$	(872,542	)	$	68,823		$	66,405

Other comprehensive income (loss):
Foreign currency translation loss, net of income tax benefit of $1,369 as of December 31, 2015	(3,980		)	(45		)	—
Comprehensive income (loss)	$	(876,522	)	$	68,778		$	66,405

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Amounts in thousands)



	Common Shares					Additional Paid-in Capital			Other Comprehensive Loss			Retained Earnings			Total
	Number of Shares		Amount, at $0.01 par value			Additional Paid-in Capital			Other Comprehensive Loss			Retained Earnings			Total
Balance, December 31, 2012	53,132		$	531		$	224,348		$	—		$	375,012		$	599,891
Issuance of restricted shares, net of forfeitures	669		7			(7		)	—			—			—
Employee tax withholding on restricted shares vesting	(74	)	(1		)	(1,374		)	—			—			(1,375		)
Issuance of common shares for stock options exercised	877		9			5,210			—			—			5,219
Tax effect of share-based compensation	—		—			3,430			—			—			3,430
Share-based compensation	—		—			22,581			—			—			22,581
Net income	—		—			—			—			66,405			66,405
Balance, December 31, 2013	54,604		546			254,188			—			441,417			696,151
Issuance of restricted shares, net of forfeitures	723		7			(7		)	—			—			—
Employee tax withholding on restricted shares vesting	(153	)	(2		)	(4,376		)	—			—			(4,378		)
Issuance of common shares for stock options exercised	159		2			831			—			—			833
Tax effect of share-based compensation	—		—			2,118			—			—			2,118
Share-based compensation	—		—			18,350			—			—			18,350
Net income	—		—			—			—			68,823			68,823
Foreign currency translation loss, net of tax	—		—			—			(45		)	—			(45		)
Balance, December 31, 2014	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 loss	—		—			—			—			(872,542		)	(872,542		)
Foreign currency translation loss, net of tax	—		—			—			(3,980		)	—			(3,980		)
Balance, December 31, 2015	120,420		$	1,204		$	997,766		$	(4,025	)	$	(362,302	)	$	632,643

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)



	Years Ended December 31,
	2015			2014			2013
Cash flows from operating activities:
Net income (loss)	$	(872,542	)	$	68,823		$	66,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	276,353			108,145			74,703
Impairment expense	791,807			—			—
Inventory write-down	31,109			—			870
Contingent consideration adjustment	(11,147		)	—			—
Deferred income taxes	(273,144		)	33,185			16,513
Provision for doubtful accounts, net of write-offs	8,071			600			689
Equity (earnings) loss from unconsolidated affiliate	(500		)	(471		)	160
(Gain) loss on disposal of assets	(544		)	(17		)	527
Share-based compensation expense	18,549			18,350			22,581
Amortization of deferred financing costs	10,926			1,168			1,160
Accretion of original issue discount	6,187			—			—
Changes in operating assets and liabilities:
Accounts receivable	278,150			(135,784		)	14,704
Inventories	21,123			(50,001		)	(10,495		)
Prepaid expenses and other current assets	(26,821		)	(12,154		)	(12,405		)
Accounts payable	(168,607		)	132,420			11,991
Payroll and related costs and accrued expenses	17,400			14,157			2,710
Income taxes payable	(108		)	(301		)	(3,888		)
Other	(3,257		)	3,717			(5,124		)
Net cash provided by operating activities	103,005			181,837			181,101
Cash flows from investing activities:
Purchases of and deposits on property, plant and equipment	(166,321		)	(307,598		)	(151,810		)
Proceeds from disposal of property, plant and equipment	4,468			719			1,151
Payments made for business acquisitions, net of cash acquired	(663,303		)	(33,533		)	(14,636		)
Investment in unconsolidated subsidiary	—			(3,000		)	—
Net cash used in investing activities	(825,156		)	(343,412		)	(165,295		)
Cash flows from financing activities:
Proceeds from revolving debt	338,000			229,000			60,000
Payments on revolving debt	(532,000		)	(64,000		)	(80,944		)
Proceeds from term loans	1,001,400			—			—
Payments on term loans	(7,950		)	—			—
Payments of capital lease obligations	(3,874		)	(4,165		)	(2,184		)
Financing costs	(55,450		)	(2,265		)	—
Proceeds from issuance of common shares for stock options exercised	453			833			5,219
Registration costs associated with issuance of common shares	(1,465		)	—			—
Employee tax withholding on restricted shares vesting	(2,621		)	(4,378		)	(1,375		)
Excess tax benefit (expense) from share-based compensation	(2,367		)	2,153			3,450
Net cash provided by (used in) financing activities	734,126			157,178			(15,834		)

Effect of exchange rate on cash	3,908			—			—

Net increase (decrease) in cash and cash equivalents	15,883			(4,397		)	(28		)
Cash and cash equivalents, beginning of year	10,017			14,414			14,442
Cash and cash equivalents, end of year	$	25,900		$	10,017		$	14,414
Supplemental cash flow disclosures:
Cash paid for interest	$	64,950		$	8,525		$	5,473
Income taxes paid (refunded)	$	(13,815	)	$	16,125		$	38,819
Non-cash investing and financing activity:
Capital lease obligations	$	—		$	25,847		$	13,487
Change in accrued capital expenditures	$	(42,793	)	$	8,120		$	6,177
Non-cash consideration for business acquisition	$	735,125		$	—		$	2,556

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

C&J Energy Services Ltd. (together with its consolidated subsidiaries, including C&J International B.V. and C&J International Middle East FZCO, “C&J” or the “Company”) is a publicly traded corporation listed on the New York Stock Exchange ("NYSE") under the symbol “CJES.” The Company provides well construction, well completions, well support and other complementary oilfield services to oil and gas exploration and production companies primarily in North America. As one of the largest completion and production services companies in North America, C&J offers a full, vertically integrated suite of services involved in the entire life cycle of the well, including directional drilling, cementing, hydraulic fracturing, cased-hole wireline, coiled tubing, rig services, fluids management services and other special well site services. The Company operates in all of the major oil and gas producing regions of the continental United States and Western Canada. The Company also has an office in Dubai and is working to establish an operational presence in key countries in the Middle East.

On March 24, 2015, C&J Energy Services, Inc. (“Legacy C&J”) and Nabors Industries Ltd. (“Nabors”) completed the combination of Legacy C&J with Nabors’ completion and production services business (the “C&P Business”), whereby Legacy C&J became a subsidiary of C&J Energy Services Ltd. (the “Merger”). The resulting combined company is currently led by the former management team of Legacy C&J.

Upon the closing of the Merger, shares of common stock of Legacy C&J were converted into common shares of C&J on a 1-for-1 basis and C&J's common shares began trading on the NYSE under the ticker “CJES.” C&J is the successor issuer to Legacy C&J following the closing of the Merger and is deemed to succeed to Legacy C&J’s reporting history under the Exchange Act.

At the closing of the Merger, Nabors received total consideration of approximately $1.4 billion 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 approximately $714.8 million in C&J common shares. Upon the closing of the Merger, Nabors owned approximately 53% of the outstanding and issued common shares of C&J, with the remainder held by former Legacy C&J shareholders. As discussed in more detail in Note 10 – Mergers and Acquisitions, Legacy C&J and Nabors determined that Legacy C&J possessed the controlling financial interest in C&J and subsequently concluded the business combination should be treated as a reverse acquisition with Legacy C&J as the accounting acquirer.

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 a result of the Merger, the Company revised its reportable business segments late in the first quarter of 2015. The Company’s revised reportable segments are: (1) Completion Services, which includes the Company's hydraulic fracturing services, cased-hole wireline services, coiled tubing services and other stimulation services; (2) Well Support Services, which includes the Company's rig services, fluids management services, and other special well site services; and (3) Other Services, which includes the Company’s smaller service lines and divisions, such as directional drilling services, cementing services, equipment manufacturing and repair, specialty chemicals sales, and research and technology. The Company manages several of its vertically integrated businesses through its research and technology division, including its data acquisition and control instruments provider and its artificial lift applications provider.

This segment structure reflects the financial information and reports used by the Company’s management, specifically its Chief Operating Decision Maker, to make decisions regarding the Company’s business, including resource allocations and performance assessments. This segment structure reflects the Company’s current operating focus in compliance with Accounting Standards Codification No. 280 - Segment Reporting. As a result of the revised segment structure, the Company has restated the corresponding items of segment information for all periods presented. The revised segment structure and the related presentation changes did not impact consolidated net income (loss), earnings (loss) per share, total current assets, total assets or total shareholders’ equity. See Note 11 - Segment Information for further discussion regarding the Company’s reportable segments.

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

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

indicates otherwise, as used herein, the terms “C&J” or the “Company”, or like terms refer to Legacy C&J and its subsidiaries when referring to time periods prior to March 24, 2015 and refer to C&J and its subsidiaries (which include Legacy C&J and its subsidiaries) when referring to time periods subsequent to March 24, 2015.

Correction of Immaterial Errors. 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.

Reclassifications. Certain reclassifications have been made to prior period consolidated financial statements to conform to current period presentations.

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 and share-based compensation. 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.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are 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, 2015 and 2014, the allowance for doubtful accounts totaled $7.9 million and $2.2 million, respectively. Bad debt expense of $8.1 million, $0.7 million and $0.7 million was included in selling, general, and administrative expenses on the consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013, respectively.

Inventories. Inventories for the Completion Services segment consist of finished goods, including equipment components, chemicals, proppants, supplies and materials for the segment’s operations. Inventories for the Other Services segment consists of raw materials, work-in-process and finished goods, including equipment components, supplies and materials.

Inventories are stated at the lower of cost or market (net realizable value) on a first-in, first-out basis and appropriate consideration is given to deterioration, obsolescence and other factors in evaluating net realizable value. As a result of unfavorable oil and gas industry market conditions that have continued to deteriorate, the Company determined that the market values of certain inventory items were below their cost basis and recorded expense of $31.1 million to direct costs for the year ended December 31, 2015.

Inventories consisted of the following (in thousands):

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	As of December 31,
	2015			2014
Raw materials	$	34,720		$	51,374
Work-in-process	13,574			24,408
Finished goods	58,657			47,717
Total inventory	106,951			123,499
Inventory reserve	(4,694		)	(1,327		)
Inventory, net	$	102,257		$	122,172

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 $261.8 million, $97.2 million, and $64.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Major classifications of property, plant and equipment and their respective useful lives were as follows (in thousands):



	Estimated Useful Lives	As of December 31,
	Estimated Useful Lives	2015			2014
Land	Indefinite	$	44,592		$	2,453
Building and leasehold improvements	5-25 years	153,320			107,270
Office furniture, fixtures and equipment	3-5 years	28,709			19,716
Machinery and equipment	3-10 years	1,225,505			767,415
Transportation equipment	5 years	224,057			66,456
		1,676,183			963,310
Less: accumulated depreciation		(499,894		)	(245,683		)
		1,176,289			717,627
Construction in progress		34,152			65,675
Property, plant and equipment, net		$	1,210,441		$	783,302

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 at the service line level, which consists of the well services, hydraulic fracturing, coiled tubing, wireline, pumpdown, directional drilling, cementing, artificial lift applications, international coiled tubing, equipment manufacturing and repair services, specialty chemicals and data acquisition and control instruments provider service lines as well as the vertically integrated research and technology service line. 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.

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

It was concluded that the sharp fall in commodity prices during the second half of 2014 constituted a triggering event that has resulted in a significant slowdown in activity across the Company’s customer base, which in turn has increased competition and has put pressure on pricing for its services throughout 2015. Although the severity and extent of this continued downturn is uncertain, absent a significant recovery in commodity prices, activity and pricing levels may continue to decline in future periods. As a result of the triggering event during the fourth quarter of 2014, PP&E recoverability testing was performed throughout 2015 on the asset groups in each of the Company’s service lines. 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. 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 worsen, additional impairment charges may be required in future periods.

PP&E impairment expense for the year ended 2015 was recognized across each asset group as follows (in thousands):



	Impairment Expense
Hydraulic Fracturing	$	255,283
Coiled Tubing	94,546
Directional Drilling	6,625
International Coiled Tubing	6,931
Equipment Manufacturing and Repair Services	13,847
Specialty Chemicals	3,070
Research and Technology	12,777
Total PP&E impairment expense	$	393,079

Goodwill, Indefinite-Lived Intangible Assets and Definite-Lived Intangible Assets. Goodwill is allocated to the Company’s three reporting units: Completion Services, Well Support Services and Other Services, all of which are consistent with the presentation of the Company’s three reportable segments. 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. See Note 3 - 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.

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 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. Further information regarding the Company's impairment analysis may be found in Note 3 - Goodwill and Other Intangible Assets.

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. These intangibles are reviewed for impairment when events or changes in circumstances (a triggering event) indicate that the asset may have a net book value in excess of recoverable value. In these cases, the Company performs a recoverability test on its definite-lived intangible assets by comparing the estimated future net undiscounted cash flows expected to be generated from the use of the asset to the carrying amount of the asset for recoverability. If the estimated undiscounted cash flows exceed the carrying amount of the asset, 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 asset, the asset is not recoverable and the amount of impairment must be determined by fair valuing the asset.

Deferred Financing Costs. Costs incurred to obtain 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 $10.9 million, $1.2 million and $1.2 million for the years ended December 31, 2015, 2014 and 2013, respectively. Accumulated amortization of deferred financing costs was $10.5 million and $3.7 million at December 31, 2015 and 2014, respectively. Estimated future amortization expense relating to deferred financing costs is as follows (in thousands):



Years Ending December 31,

2016	$	9,311
2017	9,853
2018	10,432
2019	9,904
2020	4,287
2021	3,652
2022	870
	$	48,309

Completion Services Segment

Hydraulic Fracturing Revenue. Through its hydraulic fracturing service line, the Company provides hydraulic fracturing services on a spot market basis or pursuant to contractual arrangements, such as term contracts and pricing agreements. 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 to the customer’s satisfaction, a field ticket is written that includes charges for the service 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.

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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

Well Support Services Segment

Other Services Segment

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

production services. Additionally, the Company manages several of its vertically integrated business through its research and technology division, which is included within the Other Services Segment.

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, 2015, only nonqualified stock options and restricted shares had been granted under such plans. The Company values option grants based on the grant date fair value by using the Black-Scholes option-pricing model and values restricted stock grants based on the closing price of C&J’s common shares on the grant date. 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 5 – Share-Based Compensation.

Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, long-term debt and capital lease obligations. The recorded values of cash and cash equivalents, accounts receivable, accounts payable, capital lease obligations and the revolving credit facility approximate their fair values. The following table compares the carrying value of the Company's term debt instruments to its fair value as of December 31, 2015 (See Note 2 – Long-Term Debt and Capital Lease Obligations for further discussion regarding the Company’s senior secured debt facilities):



	December 31, 2015
	Carrying Value		Fair Value
	(In thousands)
Five-Year Term Loans, net of original issue discount	$	550,825	$	503,540
Seven-Year Term Loans, net of original issue discount	$	448,812	$	406,280

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.

The carrying value of the Company's equity method investments at December 31, 2015 and December 31, 2014 was $14.3 million and $7.0 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 $0.5 million for each of the years ended December 31, 2015 and 2014 and ($0.2 million) for the year ended December 31, 2013, and is included in other expense, net, on the consolidated statements of operations.

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes. The Company accounts for income taxes using 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 bases. 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 of a change in tax rates is recognized as income or expense in the period that includes the enactment date.

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% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer 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. However, there were no material amounts recognized relating to interest and penalties in the consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013, respectively. The Company had no uncertain tax positions as of December 31, 2015.

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.

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



	Years Ended December 31,
	2015			2014		2013
	(In thousands, except per share amounts)
Numerator:
Net income (loss) attributed to common shareholders	$	(872,542	)	$	68,823	$	66,405
Denominator:
Weighted average common shares outstanding - basic	102,853			53,838		53,038
Effect of potentially dilutive securities:
Stock options	—			2,245		2,096
Restricted stock	—			430		233
Weighted average common shares outstanding - diluted	102,853			56,513		55,367
Net income (loss) per common share:
Basic	$	(8.48	)	$	1.28	$	1.25
Diluted	$	(8.48	)	$	1.22	$	1.20

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

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Years Ended December 31,
	2015	2014	2013
	(In thousands)
Basic earnings per share:
Unvested restricted stock	2,610	1,448	1,194
Diluted earnings per share:
Anti-dilutive stock options	3,661	201	1,054
Anti-dilutive restricted stock	2,125	3	164
Potentially dilutive securities excluded as anti-dilutive	5,786	204	1,218

Recent Accounting Pronouncements.

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers ("ASU 2015-14"), which deferred the effective date of ASU 2014-09 for all entities by one year and is effective for the Company's fiscal year beginning January 1, 2018. ASU 2015-14 permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method nor has the effect of the standard on ongoing financial reporting been determined.

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. For public entities, ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. ASU 2015-03 is to be applied on a retrospective basis and represents a change in accounting principle. In addition, in August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ("ASU 2015-15"). ASU 2015-15 clarifies the guidance in ASU 2015-03 regarding presentation and subsequent measurement of debt issuance costs related to line-of-credit arrangements. The SEC Staff announced they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company does not expect the adoption of these standards to have a material effect on its 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 guidance will require prospective application at the beginning of the Company's first quarter of fiscal 2018, but permits adoption in an earlier period. The Company is currently evaluating the impact, if any, of adopting this new accounting standard on its results of operations and financial position.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments ("ASU 2015-16"). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The acquirer must record, in the same period's financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. ASU 2015-16 is effective for the Company's fiscal year beginning January 1, 2016. The Company is currently evaluating the impact, if any, of adopting this new accounting standard on its results of operations and financial position.

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 is required to adopt this ASU for years beginning after December 15, 2016, with early adoption permitted, and the guidance may be applied either prospectively or retrospectively. The Company does not expect this ASU to have a material impact on its consolidated financial statements.

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 - Long-Term Debt and Capital Lease Obligations

Long-term debt consisted of the following (in thousands):



	As of December 31,
	2015			2014

Legacy C&J senior secured credit facility repaid in connection with the Merger	$	—		$	315,000
Revolving credit facility maturing on March 24, 2020	121,000			—
Five-Year Term Loans, net of original issue discount of $19,863, maturing on March 24, 2020	550,825			—
Seven-Year Term Loans, net of original issue discount of $32,550, maturing on March 24, 2022	448,812			—
Capital leases	34,873			38,748
Total debt and capital lease obligations	1,155,510			353,748
Less: current portion of long-term debt and capital lease obligations	(13,433		)	(3,873		)
Long-term debt and capital lease obligations	$	1,142,077		$	349,875

Credit Agreement

On March 24, 2015, in connection with the closing of the Merger, the Company entered into a new credit agreement with Bank of America N.A., as administrative agent and other lending parties (the “Original Credit Agreement”). At the closing, 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”) in the aggregate principal amount of $1.06 billion. The Company simultaneously repaid all amounts outstanding and terminated Legacy C&J’s prior credit agreement; no penalties were due in connection with such repayment and termination. The borrowers under the Revolver are the Company and certain wholly-owned subsidiaries of the Company, specifically, CJ Lux Holdings S.à. r.l. and CJ Holding Co. The borrower under the Term Loan B is CJ Holding Co. All obligations under the Original Credit Agreement are guaranteed by the Company’s wholly-owned domestic subsidiaries, other than immaterial subsidiaries.

On September 29, 2015, the Company obtained and entered into a waiver and amendments to the Original Credit Agreement (as amended by the amendments, the "Amended Credit Agreement"). The Amended Credit Agreement, among other things, suspends the quarterly maximum Total Leverage Ratio (defined below) and quarterly minimum Interest Coverage Ratio (defined below) covenants set forth in the Original Credit Agreement. The suspension of these financial covenants commenced with the fiscal quarter ending September 30, 2015 and will last through the fiscal quarter ending June 30, 2017. Upon reinstatement of these covenants as of the quarter ending September 30, 2017, the required levels initially will be more lenient than those in effect under the terms of the Original Credit Agreement and will gradually adjust to those prior levels over the subsequent fiscal quarters (see Other Information below). The effectiveness of the covenant suspension is also subject to certain conditions that, among other things, will reduce the capacity of the Company to make investments and restricted payments through the quarter ending December 31, 2017.

The Amended Credit Agreement also provides for new financial covenants that will apply in lieu of the Total Leverage Ratio and Interest Coverage Ratio previously in effect under the Original Credit Agreement, including the following:


•	Implementation of a quarterly minimum EBITDA covenant, commencing with the quarter ending September 30, 2015 and running through the quarter ending June 30, 2017, based on negotiated EBITDA levels and with cushion baskets available for any EBITDA shortfalls through the third quarter of 2016;


•	A permanent reduction in the maximum borrowing capacity under the Revolver from $600 million to $400 million;


•	A collateral coverage covenant running through the quarter ending March 31, 2018, which limits outstanding Revolver borrowings and letters of credit to the greater of (i) $300.0 million and (ii) an amount derived from

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

80% of Eligible Receivables and 50% of Eligible Inventory (each as defined in the Amended Credit Agreement) (subject to the reduced $400 million borrowing capacity described above);


•	Increases to the applicable rate on Revolver borrowings by (i) 50 basis points in the event that the Company’s most recently reported total leverage ratio is greater than 4.00:1.00 and less than or equal to 4.50:1.00 and (ii) 100 basis points in the event that the Company’s most recently reported total leverage ratio is greater than 4.50:1.00; and


•	Quarterly limitations on capital expenditures for the quarter ending December 31, 2015, and annual limitations on capital expenditures for the four fiscal quarter periods ending December 31, 2016 through June 30, 2017.

Revolving Credit Facility

As of December 31, 2015, $121.0 million was outstanding under the Revolver along with $12.6 million of outstanding letters of credit, leaving $166.4 million of available borrowing capacity based on $300 million of availability as a result of the collateral coverage test implemented under the Amended Credit Agreement.

The Revolver matures on March 24, 2020 (except that if any Five-Year Term Loans (as defined below) have not been repaid prior to September 24, 2019, the Revolver will mature on September 24, 2019). Borrowings under the Revolver are non-amortizing.

Amounts outstanding under the Revolver bear interest based on, at the option of the borrower, the London Interbank Offered Rate (“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 (the “Total Leverage Ratio”).

The Revolver also requires that the Company pay a commitment fee equal to a percentage of unused commitments which varies based on the Total Leverage Ratio.

Subject to certain conditions and limitations, the Amended Credit Agreement permits the Company to increase the aggregate commitments under the Revolver in a total principal amount of up to $100.0 million.

The Revolver is permitted to be prepaid from time to time without premium or penalty.

Term Loan B Facility

Borrowings under the Term Loan B are 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 is required to make quarterly amortization payments in an amount equal to 1.00% per annum, with the remaining balance payable on the applicable maturity date. As of December 31, 2015, the Company had borrowings outstanding under the Five-Year Term Loans and the Seven-Year Term Loans of $570.7 million and $481.4 million, respectively.

Five-Year Term Loans outstanding under the Term Loan B bear interest based on, at the option of the Company, (i) LIBOR subject to a floor of 1.00% per annum, plus a margin of 5.50%, or (ii) an alternative base rate, plus a margin of 4.50%. Seven-Year Term Loans outstanding under the Term Loan B will bear interest based on, at the option of the Company, (i) LIBOR subject to a floor of 1.00% per annum, plus a margin of 6.25%, or (ii) an alternative base rate, plus a margin of 5.25%. The Term Loan B also contains ‘most favored nation’ pricing protection requiring that if the effective yield (giving effect to, among other things, consent fees paid to the lenders) of the Five-Year Term Loans increases by more than 50 basis points, the effective yield of the Seven-Year Term Loans must increase by the same amount less 50 basis points.

The alternative base rate is equal to the highest of (i) the Administrative Agent’s prime rate, (ii) the Federal Funds Effective Rate plus 0.50%, or (iii) LIBOR plus 1.00%.

The Term Loan B is required to be prepaid under certain circumstances and exceptions including (i) in the event that C&J and its subsidiaries generate Excess Cash Flow (as defined in the Credit Agreement) in any fiscal year-end, in an amount equal to 50% of the Excess Cash Flow for such fiscal year if the Total Leverage Ratio as of the end of such fiscal

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

year is 3.25:1.00 or greater, (ii) in the event of a sale or other disposition of property by C&J or its subsidiaries, in an amount equal to 100% of the net proceeds of such sale or disposition, subject to customary reinvestment rights and other exceptions, and (iii) in the event of an incurrence of debt not permitted under the Credit Agreement, in an amount equal to 100% of the net proceeds of such debt.

As of December 31, 2015, maturities under the Term Loan B facility are as follows (in thousands):



2016	$	10,600
2017	10,600
2018	10,600
2019	10,600
2020	552,538

As of December 31, 2015, the weighted average interest rate of borrowings under the Credit Agreement was 6.5%.

Other Information

The Amended Credit Agreement contains customary restrictive covenants (in each case, subject to exceptions) that limit, among other things, the ability of the Company and its subsidiaries to create, incur, assume or suffer to exist liens or indebtedness, sell or otherwise dispose of their assets, make certain restricted payments and investments, enter into transactions with affiliates, make capital expenditures and prepay certain indebtedness. The Amended Credit Agreement also contains financial covenants applicable to the Revolver and the Five-Year Term Loans only, which include: (i) a maximum Total Leverage Ratio of 5.50:1.00 for the fiscal quarter ending September 30, 2017, 5.00:1.00 for the fiscal quarter ending December 31, 2017, 4.50:1.00 for the fiscal quarter ending March 31, 2018, 4.25:1.00 for the fiscal quarter ending June 30, 2018 and 4.00:1.00 for each fiscal quarter thereafter; (ii) a minimum quarterly ratio of consolidated EBITDA of C&J and its subsidiaries to consolidated interest expense of C&J and its subsidiaries ("Interest Expense Ratio") of 2.50:1.00 for the fiscal quarters ending September 30, 2017 and December 31, 2017, 2.75:1.00 for the fiscal quarter ending March 31, 2018 and 3.00:1.00 for each fiscal quarter thereafter; and (iii) starting September 30, 2015 and until the fiscal quarter ending June, 30, 2017, a Minimum Cumulative Consolidated EBITDA covenant as follows (in thousands):



	Minimum Cumulative Consolidated EBITDA ⁽¹⁾	Cumulative Cushion Amount
Three months ended September 30, 2015	$(15,000)	$10,000
Three months ended December 31, 2015	$10,000	$20,000
Six months ended March 31, 2016	$28,000	$40,000
Nine months ended June 30, 2016	$63,000	$60,000
Twelve months ended September 30, 2016	$121,000	$60,000
Twelve months ended December 31, 2016	$115,000	None
Twelve months ended March 31, 2017	$165,000	None
Twelve months ended June 30, 2017	$205,000	None

(1) Minimum Cumulative Consolidated EBITDA is defined as total earnings (loss) before net interest expense, income taxes, depreciation and amortization, other income (expense), and net gain or loss on disposal of assets, and excludes, among other things, stock based compensation expense, acquisition-related costs, and non-routine items.

The Company may use some or all of the “Cumulative Cushion Amount” set forth above to increase the Cumulative Consolidated EBITDA for the specified given period for purposes of satisfying the Minimum Cumulative Consolidated EBITDA test applicable to such period. However, in the event the Company utilizes only some of the Cumulative Cushion Amount for such period, any unused amount for such period will not be added to the Cumulative Cushion Amount specified for any future period.

In the event utilization and pricing levels remain at or fall below existing levels for a sustained period, the Company may be unable to comply with one or more financial covenants in future periods.

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Capital Lease Obligations

In 2013, the Company entered into “build-to-suit” lease agreements for the construction of a new, technology-focused research and development facility and new corporate headquarters, respectively. Each lease is accounted for as a capital lease.

The lease for the technology facility commenced upon completion of construction in October 2013, creating a capital lease obligation of $13.5 million and accumulated amortization was $1.7 million at December 31, 2015. The lease is payable monthly in amounts ranging from $93 thousand to $128 thousand over the term of the lease, including interest at approximately 2.7% per year, and has an initial term of 12 years. Cumulative future lease payments through the initial term are $15.9 million, of which approximately $2.4 million represents interest expense.

The lease for the corporate headquarters commenced upon completion of construction in April 2014, creating a capital lease obligation of $25.6 million and accumulated amortization was $2.8 million at December 31, 2015. The lease is payable monthly in amounts ranging from $181 thousand to $238 thousand over the term of the lease, including interest at approximately 2.7% per year, and has an initial term of 12 years. Cumulative future lease payments through the initial term are $30.3 million, of which approximately $4.7 million represents interest expense.

In addition, the Company leases certain service equipment, with the intent to purchase, under non-cancelable capital leases. The terms of these contracts range from three to four years with varying payment dates throughout each month.

As of December 31, 2015, the future minimum lease payments under the Company’s capital leases are as follows (in thousands)




Years Ending December 31,

2016	$	3,734
2017	3,584
2018	3,685
2019	3,785
2020	3,887
Thereafter	21,385

	$	40,060

As of December 31, 2015, the interest expense associated with the future minimum lease payments under the Company’s capital leases totals $5.2 million.

Note 3 - Goodwill and Other Intangible Assets

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 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. The Step 1 testing revealed potential impairment for the Completion Services and Other Services reporting units, and the Step 2 test findings revealed that there was no value remaining to be allocated to the goodwill associated with these two reporting units. As a result, the Company recognized impairment expense of $347.7 million for the Completion Services reporting unit and $37.3 million for the Other Services reporting unit, both which included adjustments during the fourth quarter as a result of finalizing the fair value estimates for these two reporting units.

During the fourth quarter of 2015, the Company determined no further impairment write-down was considered necessary.

Income approach

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 September 30, 2015, and management’s anticipated business outlook, both of which have 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 16.0% for both Completion Services and Other Services and 14.0% for Well Support 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 8.0x for all three reporting units.

The fair value determined under the market approach is sensitive to these market multiples, and a decline in any of the multiples could reduce the estimated fair value of the one remaining reporting unit below its carrying value. 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 generally consistent with the estimated fair value determined under the market approach. For purposes of the goodwill impairment test, the concluded fair value for each of the three reporting units consisted of a weighted average, with an 80% weight under the income approach and a 20% weight under the market approach.

The results of the Step 1 impairment testing for the Well Support Services reporting unit during the third quarter of 2015 indicated its estimated fair value exceeded its carrying value by approximately 11%, and it was concluded that the goodwill balance of $314.4 million was not impaired as of September 30, 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.

A decline in the Well Support Services reporting unit cash flow projections or changes in other key assumptions may result in a goodwill impairment charge in the future.

The changes in the carrying amount of goodwill for the year ended December 31, 2015 are as follows (in thousands):



	Completion Services			Well Support Services			Other Services			Total
As of December 31, 2014	$	206,465		$	—		$	13,488		$	219,953
Acquisitions	141,435			309,541			24,700			475,676
Impairment expense	(347,652		)	—			(37,316		)	(384,968		)
Foreign currency translation and other adjustments	(248		)	(1,864		)	(872		)	(2,984		)
As of December 31, 2015	$	—		$	307,677		$	—		$	307,677

Indefinite-Lived Intangible Assets

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company had approximately $7.6 million of intangible assets with indefinite useful lives, which are subject to annual impairment tests or more frequently if events or circumstances indicate the carrying amount may not be recoverable.

As noted above, during the third quarter of 2015, sustained low commodity price levels and the resulting impact on the Company’s results of operations including its equipment manufacturing business line, coupled with the sustained decrease in the Company’s share price were deemed triggering events that led to a detailed impairment test on the Total Equipment trade name using a relief from royalty method. Based on the results of the impairment testing, the trade name estimated fair value was less than the carrying value by approximately $2.5 million, and it was therefore determined that the trade name was impaired as of September 30, 2015. The Company recorded impairment expense of $2.5 million to reflect the trade name at its fair value. In addition, as part of the valuation performed, the Company determined the trade name no longer possessed an indefinite life. As of September 30, 2015, the trade name was categorized as a definite-lived intangible asset and is being amortized over its remaining estimated useful life.

The Company’s intangible assets associated with intellectual property, research and development (“IPR&D”) consist of technology that is still in the testing phase, and management continues to actively pursue development and planned marketing of the new technology. Based on the Company's evaluation which includes successful test results within its research and development facilities, it was determined that the IPR&D carry value of $7.6 million was not impaired as of December 31, 2015.

Definite-Lived Intangible Assets

The Company reviews definite-lived intangible assets for impairment when events or changes in circumstances (a triggering event) indicate that the asset may have a net book value in excess of recoverable value. During the third quarter of 2015 and continuing into the fourth quarter, as noted above 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 recoverability test on all of its definite-lived intangible assets which compares the estimated future net undiscounted cash flows expected to be generated from the use of the asset to the carrying amount of the asset for recoverability. If the estimated undiscounted cash flows exceed the carrying amount of the asset, 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 asset, the asset is not recoverable and the amount of impairment must be determined by fair valuing the asset.

Recoverability testing resulted in intangible assets associated with the Company’s equipment manufacturing and research and technology lines of business, and included within the Other Services segment, were not recoverable. The fair value of these assets was determined to be zero, resulting in impairment expense of $11.2 million.

The changes in the carrying amounts of other intangible assets for the year ended December 31, 2015 are as follows (in thousands):

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Amortization Period	December 31, 2014			Acquisitions		Impairment Expense			Amortization Expense			Move from Indefinite-Lived to Definite- Lived			Foreign Currency Translation Adjustment			December 31, 2015
Customer relationships	8-15 years	$	116,073		$	16,400	$	(9,594	)	$	—		$	—		$	(65	)	$	122,814
Trade name	10-15 years	29,315			9,900		(253		)	—			3,700			(82		)	42,580
Developed technology	5-15 years	2,110			19,600		(1,367		)	—			—			(446		)	19,897
Non-compete	4-5 years	1,810			900		—			—			—			—			2,710
Patents	10 years	—			373		—			—			—			—			373
IPR&D	Indefinite	7,598			—		—			—			—			—			7,598
Trade name - Total Equipment	Indefinite	6,247			—		(2,547		)	—			(3,700		)	—			—
		163,153			47,173		(13,761		)	—			—			(593		)	195,972
Less: accumulated amortization		(33,685		)	—		—			(14,516		)	—			90			(48,111		)
Intangible assets, net		$	129,468		$	47,173	$	(13,761	)	$	(14,516	)	$	—		$	(503	)	$	147,861

Amortization expense for the years ended December 31, 2015, 2014 and 2013 totaled $14.5 million, $10.9 million and $10.1 million, respectively.

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




Years Ending December 31,

2015	$	14,933
2016	14,759
2017	14,759
2018	14,735
2019	12,952
Thereafter	68,125

	$	140,263

Note 4 – Income Taxes

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

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Years Ended December 31,
	2015			2014			2013
Current provision:
Federal	$	(23,784	)	$	11,184		$	22,870
State	(2,265		)	1,310			1,930
Foreign	100			—			—
Total current provision	(25,949		)	12,494			24,800
Deferred (benefit) provision:
Federal	(248,279		)	31,978			14,864
State	(20,553		)	2,036			1,705
Foreign	(4,312		)	(829		)	(56		)
Total deferred provision	(273,144		)	33,185			16,513
Provision for income taxes	$	(299,093	)	$	45,679		$	41,313

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



	Years Ended December 31,
	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
State taxes, net of federal benefit	1.4	%	3.0	%	2.8	%
Domestic production activities deduction	(0.2	)%	(1.0	)%	(1.8	)%
Effect of foreign losses	(0.3	)%	2.4	%	0.7	%
Impairment	(9.8	)%	—	%	—	%
Other	(0.6	)%	0.5	%	1.7	%
Effective income tax rate	25.5	%	39.9	%	38.4	%

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

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	As of December 31,
	2015			2014
Deferred tax assets:
Accrued liabilities	$	4,588		$	5,419
Allowance for doubtful accounts	7,364			822
Stock-based compensation	1,337			1,027
Inventory	8,712			641
Other	1,039			197
Current deferred tax assets	23,040			8,106
Stock-based compensation	18,166			16,896
Net operating losses	84,166			1,181
Accrued liabilities	3,458			69
Other	2,528			—
Non-current deferred tax assets	108,318			18,146
Total deferred tax assets	131,358			26,252
Valuation allowance	(77		)	—
Total deferred tax assets, net	131,281			26,252
Deferred tax liabilities:
Prepaid assets	(9,677		)	—
Contingent consideration liabilities	(4,328		)	—
Current deferred tax liability	(14,005		)	—
Depreciation on property, plant and equipment	(228,981		)	(161,782		)
Amortization of goodwill and intangible assets	(28,033		)	(49,704		)
Other	(378		)
Non-current deferred tax liabilities	(257,392		)	(211,486		)
Net deferred tax liability	$	(140,116	)	$	(185,234	)

The Company has approximately $207.1 million of U.S. federal net operating loss carryforwards (“NOL’s”) which, if not utilized, will expire in the year 2035 and state NOL’s of approximately $121.5 million which, if not utilized, will expire in various years between 2025 and 2035. Additionally, the Company has approximately $13.5 million of NOL's in other jurisdictions which, if not utilized, will expire in various years between 2020 and 2035. As of December 31, 2015 we have recorded a deferred tax asset of approximately $84.2 million relating to NOL's. A valuation allowance of $0.1 million has been provided for NOL's that the Company believes are more likely than not to expire unutilized.

The Company’s U.S. federal income tax returns for the tax years 2012 through 2014 remain open to examination by the Internal Revenue Service ("IRS") 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 2011. The Company’s 2011, 2012 and 2013 Louisiana tax returns are currently under examination.

During the year ended December 31, 2015, the company recorded deferred charges relating to income tax expense on intercompany profits that resulted from the sale of our intellectual property rights outside of North America to our subsidiary in Luxembourg. The deferred charges, which total $16.5 million, are included within other non-current assets on the consolidated balance sheet. The deferred charges are amortized as a component of income tax expense over the economic life of the intellectual property.

Note 5 - Share-Based Compensation

Equity Plans

In connection with the 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 Merger. The 2015 LTIP served as an assumption of the Legacy C&J 2012 Long-Term Incentive Plan, including the sub-plan titled the C&J International Middle East FZCO Phantom Equity Arrangement (the “2012 LTIP”), with certain non-material revisions made

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Legacy C&J employees, consultants and non-employee directors were granted under the 2012 LTIP and, following the 2015 LTIP’s adoption, no further awards will be granted under the 2012 LTIP. Awards that were previously outstanding under the 2012 LTIP will continue and remain outstanding under the 2015 LTIP, as adjusted to reflect the Merger. At the closing of the 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 Merger.

The 2015 LTIP 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 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, 2015 only nonqualified stock options and restricted shares have been awarded under the 2015 LTIP and 2012 LTIP.

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. Approximately 3.7 million shares were available for issuance under the 2015 LTIP as of December 31, 2015. The number of common shares available for issuance under the 2015 LTIP 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 common shares available for issuance may also increase due to the termination of an award granted under the 2015 LTIP, the 2012 LTIP or the Prior Plans (as defined below), by expiration, forfeiture, cancellation or otherwise without the issuance of the common shares.

Prior to the approval of the 2012 LTIP, all share-based awards granted to Legacy C&J’s employees, consultants and non-employee directors were granted under the C&J Energy Services 2006 Stock Option Plan and subsequently under the C&J Energy Services 2010 Stock Option Plans (collectively known as the “Prior Plans”). No additional awards will be granted under the Prior Plans.

On February 1, 2016, the shareholders of the Company approved the Second Amendment to the 2015 LTIP , which provides for (i) an increase of 6.0 million common shares that may be issued under the 2015 LTIP, (ii) an increase of 3.0 million common shares in the per participant annual limit, from 2.0 million to 5.0 million, that may be awarded under the 2015 LTIP and (iii) an increase of $5.0 million in the per-participant annual limit on the fair market value of certain awards designated to be paid only in cash or the settlement of which is not based on a number of common shares granted under the 2015 LTIP, from $5.0 million to $10.0 million.

Stock Options

The fair value of each option award granted under the 2015 LTIP, the 2012 LTIP and the Prior Plans is estimated on the date of grant using the Black-Scholes option-pricing model. Option awards are generally granted with an exercise price equal to the market price of the Company’s common shares on the grant date. For options granted prior to Legacy C&J’s initial public offering, which closed on August 3, 2011, the calculation of Legacy C&J’s share price involved the use of different valuation techniques, including a combination of an income and/or market approach. 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 is derived using the “plain vanilla” method. In addition, expected volatilities have been based on comparable 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, 2015, approximately 0.3 million replacement option awards were granted by the Company to employees in connection with the Merger. No options were granted during the year ended December 31, 2014.

The following table presents the assumptions used in determining the fair value of option awards during the years ended December 31, 2012 and 2015. No stock options were granted by the Company for the years ended December 31, 2013 and 2014.

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Years Ended December 31,
	2015	2012

Expected volatility	52.3%	65% - 75%
Expected dividends	None	None
Exercise price	$7.93 - $27.12	$16.88 - $18.89
Expected term (in years)	0.3 - 4.3	6
Risk-free rate	0.03% - 1.3%	0.9% - 1.4%

The weighted average grant date fair value of options granted during the years ended December 31, 2012 and December 31, 2015, was $11.45 and $4.74, respectively.

A summary of the Company’s stock option activity for the year ended December 31, 2015 is presented below.



	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
	(in thousands)				(in years)	(in thousands)
Outstanding at January 1, 2013	6,266		$	11.06	7.19	$	72,024
Granted	—		—		—	—
Exercised	(877	)	5.96		—	—
Forfeited	(106	)	21.98		—	—
Outstanding at December 31, 2013	5,283		$	11.69	6.36	$	65,351
Granted	—		—		—	—
Exercised	(159	)	5.23		—	—
Forfeited	(57	)	29.00		—	—
Outstanding at December 31, 2014	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	5,119		$	11.82	4.41	$	2,874
Exercisable at December 31, 2015	5,119		$	11.82	4.41	$	2,874

The total intrinsic value of options exercised during the years ended December 31, 2015 and 2014 was $0.6 million and $3.2 million, respectively. As of December 31, 2015, there was no more remaining unrecognized compensation cost related to outstanding stock options.

Restricted Shares

Restricted shares are 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, 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 in connection with the Merger, at fair market values ranging from $3.55 to $15.10 per share. During the year ended December 31, 2014, approximately 0.8 million restricted shares were granted by the Company to employees and non-employee directors at fair market values ranging from $14.46 to $33.14 per share.

To the extent permitted by law, the recipient of an award of restricted shares will have 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 will be deferred until the lapsing of

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the restrictions imposed on the shares and will 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, shall be made upon the lapsing of restrictions on the restricted shares, and any dividends deferred in respect of any restricted shares shall be forfeited upon the forfeiture of such restricted shares. As of December 31, 2015, the Company had not issued any dividends.

A summary of the status and changes during the year ended December 31, 2015 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 January 1, 2015	1,377		$	23.39
Granted	2,850		13.50
Forfeited	(238	)	14.81
Vested	(718	)	21.97
Non-vested at December 31, 2015	3,271		$	15.70

As of December 31, 2015 and 2014, respectively, there were $29.9 million and $18.7 million of total unrecognized compensation cost related to restricted shares. That cost is expected to be recognized over a weighted-average period of 2.12 years. The weighted-average grant-date fair value per share of restricted shares granted during the years ended December 31, 2015 and 2014, respectively, was $13.50 and $24.65.

As of December 31, 2015, the Company had 8.4 million stock options and restricted shares outstanding to employees and non-employee directors, 0.9 million of which were issued under the 2006 Plan, 4.0 million were issued under the 2010 Plan, 0.7 million were issued under the 2012 Plan and the remaining 2.8 million were issued under the 2015 Plan. As of December 31, 2014, the Company had 6.4 million of stock options and restricted shares outstanding to employees and non-employee directors, 1.0 million of which were issued under the 2006 Plan, 4.0 million were issued under the 2010 Plan and the remaining 1.4 million were issued under the 2012 Plan.

Share-based compensation expense was $18.5 million, $18.4 million and $22.6 million for the years ended December 31, 2015, 2014 and 2013, 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 $6.5 million, $6.4 million and $7.9 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Note 6 – Related Party Transactions

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 Merger. As of December 31, 2015, the Company’s payable balance is $28.2 million and the support service fees incurred during 2015 totaled $136.4 million. The payable balance is included in accounts payable on the consolidated balance sheet.

The Company obtains trucking and crane services on an arm’s length basis from certain vendors affiliated with two of its executive officers. For the years ended December 31, 2014 and 2013, purchases from these vendors totaled $7.4 million and $3.7 million, respectively, and there were no purchases from these vendors for the year ended December 31, 2015.

The Company purchases certain of its equipment on an arm’s length basis from vendors affiliated with a member of its Board of Directors. For the years ended December 31, 2015, 2014 and 2013, purchases from these vendors were $1.9 million, $5.7 million and $3.8 million, respectively. Amounts payable to these vendors at December 31, 2015 and 2014 were less than $0.1 million and $1.5 million, respectively.

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, 2015, 2014 and 2013, purchases from these vendors were $0.5

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

million, $1.0 million and $1.7 million, respectively. Amounts payable to these vendors at December 31, 2015 and 2014 were $50.6 thousand and $25.7 thousand, respectively.

The Company has an unconsolidated equity method investment with a vendor that provides the Company with raw material for its specialty chemical business. For the years ended December 31, 2015, 2014 and 2013, purchases from this vendor were $11.8 million, $21.8 million and $7.6 million, respectively. Amounts payable to these vendors at December 31, 2015 and 2014 were $1.5 million and $0.9 million, respectively.

The Company obtained drilling fluids from a vendor which was affiliated with one of its employees. For the year ended December 31, 2015, purchases from this vendor totaled $2.1 million. Accounts payable to this vendor at December 31, 2015 was $0.2 million.

The Company obtains machined parts from a vendor which is affiliated with several of its employees. For the year ended December 31, 2014, purchases from this vendor totaled $0.4 million and there was no accounts payable balance for the year ended December 31, 2014.

Note 7 – Business Concentration

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 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 53.6%, 51.1% and 64.6% of the Company’s consolidated revenue for the years ended December 31, 2015, 2014 and 2013, respectively. For the year ended December 31, 2015, revenue from one customer represented 15.5% of the Company’s consolidated revenue. For the year ended December 31, 2014, revenue from two customers individually represented 16.4% and 9.6% of the Company’s consolidated revenue. For the year ended December 31, 2013, revenue from two customers individually represented 19.5% and 13.1% of the Company’s consolidated revenue. Other than those listed above, no other customer accounted for 10% or more of the Company’s consolidated revenue in 2015, 2014 or 2013. Revenue was earned from each of these customers within the Company’s Completion Services and Well Support Services segments.

Note 8 - Commitments and Contingencies

Environmental

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

Currently, the Company has not been fined, cited or notified of any environmental violations that would have a material adverse effect upon its 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 upon the Company’s consolidated financial position, results of operation or liquidity.

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Service Equipment and Other Capital Expenditures

The Company has agreed to purchase service equipment and other capital assets for $2.1 million as of December 31, 2015. The Company expects to fulfill these commitments during 2016.

Inventory and Materials

The Company has entered into contractual agreements or commitments to purchase inventory and other materials for $102.9 million as of December 31, 2015. The Company expects to fulfill these commitments over the next 4 years.

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. At December 31, 2015, the contingent consideration liability remeasurement resulted in a $9.7 million decrease in value recorded in other income (expense), net in the consolidated statement of operations with a revised fair value of $4.7 million included in other long-term liabilities in the Company's Consolidated Balance Sheet.

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 11 years.

Lease expense under all operating leases totaled $14.2 million, $14.0 million and $14.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. As of December 31, 2014, the future minimum lease payments under non-cancelable operating leases were as follows (in thousands):




Years Ending December 31,

2016	$	9,008
2017	5,333
2018	3,279
2019	2,266
2020	1,881
Thereafter	6,070

	$	27,837

Note 9 – Employee Benefit Plans

The Company maintains two contributory profit sharing plans under a 401(k) arrangement which covers all employees meeting certain eligibility requirements. Eligible employees can make annual contributions to the plans up to the maximum amount allowed by current federal regulations. The Company matches dollar for dollar all contributions made by eligible employees up to 4% of their gross salary. The Company’s 401(k) contributions for the years ended December 31, 2015, 2014 and 2013 totaled $4.8 million, $2.3 million and $1.9 million, respectively.

Note 10 – Mergers and Acquisitions

2015

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

On March 24, 2015, Legacy C&J and Nabors completed the combination of Legacy C&J with the C&P Business. The resulting combined company, which has been renamed C&J Energy Services Ltd., is now one of the largest completion and production services providers in North America led by the former management team of Legacy C&J. At the closing of the combination, Nabors received total consideration of $1.4 billion, before 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 Legacy 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 owns approximately 53% of the outstanding and issued common shares of C&J, with the remainder held by former Legacy 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 Merger is being accounted for using the acquisition method of accounting for business combinations. In applying the acquisition method of accounting, Legacy 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% common share ownership in C&J, Legacy C&J and Nabors determined that Legacy C&J possessed the controlling financial interest, based on, among other factors, the presence of a majority of Legacy 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 Legacy C&J. Legacy C&J and Nabors therefore concluded the business combination should be treated as a reverse acquisition with Legacy C&J as the accounting acquirer.

C&J financed the cash portion of the 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 2 – Long-Term Debt and Capital Lease Obligations for further discussion on the Company’s Original Credit Agreement and Amended Credit Agreement.

The purchase price has been 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. As a result, the provisional measurements associated with these assets and liabilities are preliminary and subject to change during the measurement period and such changes could be material. Any change in the provisional measurements could impact the amount of goodwill impairment charge the Company records for the first quarter of 2016, as a portion of the goodwill associated with the Merger was allocated to the Completion Services reporting unit. All of the goodwill associated with this reporting unit was written off as of December 31, 2015.

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

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Amounts Recognized as of Merger Date			Measurement Period Adjustments ⁽¹⁾			Estimated Fair Value
Accounts receivable	$	262,973		$	7,500		$	270,473
Inventory	35,491			(7,372		)	28,119
Other current assets	8,857			(1,940		)	6,917
Property, plant and equipment	1,024,622			(57,625		)	966,997
Goodwill	444,162			6,814			450,976
Other intangible assets	28,300			13,700			42,000
Other assets	11,171			(2,856		)	8,315
Total assets acquired	1,815,576			(41,779		)	1,773,797
Accounts payable	(195,913		)	19,610			(176,303		)
Other current liabilities	(23,813		)	1,133			(22,680		)
Deferred income taxes	(187,515		)	(22,364		)	(209,879		)
Total liabilities assumed	(407,241		)	(1,621		)	(408,862		)
Net assets acquired	$	1,408,335		$	(43,400	)	$	1,364,935

(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 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 $270.5 million and $296.2 million, respectively. Based on the age of certain accounts receivable, a portion of the gross contractual amount is 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	$	41,391
Building and leasehold improvements	2-25	77,887
Office furniture, fixtures and equipment	2-5	2,845
Machinery & Equipment	2-10	660,855
Transportation equipment	2-5	139,070
Construction in progress		44,949

Property, plant and equipment		$	966,997

Other intangibles have a total preliminary 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 $309.6 million allocated to Well Support Services. The goodwill recognized as a result of the Merger was primarily attributable to the increased economies of scale, capabilities, resources and geographic footprint of the combined company as well as the cost savings opportunities as C&J capitalizes 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.

The Company has treated the Merger as a non-taxable transaction. Such treatment results in the acquired assets and liabilities having carryover basis for tax purposes. A deferred tax liability in the amount of $209.9 million was recorded to account for the differences between the preliminary purchase price allocation and carryover tax basis.

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Acquisition-related costs associated with the 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 Merger was completed on January 1, 2014. Pro forma amounts are based on the preliminary purchase price allocation of the acquisition and are not necessarily indicative of results that may be reported in the future (in thousands, except per share data):



	Year Ended December 31, 2015			Year Ended December 31, 2014
Revenues	$	2,114,671		$	3,861,412
Net loss	$	(879,231	)	$	(244,183	)
Net loss per common share:
Basic	$	(7.52	)	$	(2.09	)
Diluted	$	(7.52	)	$	(2.09	)

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 a contingent consideration valued at approximately $14.4 million, subject to customary working capital adjustments following closing. Artificial Lift Provider's results of operations since the date of the acquisition through December 31, 2015, specifically including revenue of $3.4 million and a net loss of $(30.0 million), have been included in the Company’s consolidated financial statements and are reflected in "Other Services" in Note 11 – Segment Information.

The purchase price 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	24,700
Other intangible assets	5,173
Total assets acquired	38,224
Current liabilities	(1,927		)
Deferred income taxes	(2,067		)
Other liabilities	(276		)
Total liabilities assumed	(4,270		)
Net assets acquired	$	33,954

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 contingent consideration was determined using a Monte Carlo simulation discounted cash flow model over many simulated possible future outcomes which yielded a value of $14.4 million. The contingent consideration is remeasured on a fair value basis each quarter until the contingent consideration is paid or expires. At December 31, 2015, the contingent consideration remeasurement resulted in a $9.7 million decrease in value recorded in other income (expense), net in the consolidated statement of operations with a revised fair value of $4.7 million included in other long-term liabilities in the Company's Consolidated Balance Sheet.

2014

Acquisition of Tiger

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On May 30, 2014, the Company acquired all of the outstanding equity interests of Tiger for approximately $33.2 million, including working capital adjustments.

Tiger provides cased-hole wireline, logging, perforating, pipe recovery and tubing-conveyed perforating services. The acquisition of Tiger increased the Company’s existing wireline capabilities and provides a presence on the U.S. West Coast. The results of Tiger’s operations since the date of the acquisition have been included in the Company’s consolidated financial statements and are reflected in the Completion Services segment in Note 11 – Segment Information.

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




Current assets	$	3,851
Property and equipment	8,176
Goodwill	14,671
Other intangible assets	17,340

Total assets acquired	$	44,038


Current liabilities	$	1,223
Deferred income taxes	8,556
Other liabilities	1,015

Total liabilities assumed	$	10,794

Net assets acquired	$	33,244

2013

Other Acquisitions

In April 2013, the Company acquired all of the outstanding common shares of a provider of directional drilling technology and related downhole tools. The aggregate purchase price of the acquisition was approximately $9.0 million.

In December 2013, the Company acquired all of the outstanding stock of a manufacturer of data control instruments. The aggregate purchase price of the acquisition was approximately $6.7 million.

Note 11 - Segment Information

In accordance with Accounting Standards Codification 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 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.

Due to the transformative nature of the Merger, the CODM changed the way in which the Company is managed, including a revised segment approach in making performance evaluation and resource allocation decisions. Discrete financial information was created to provide the segment information necessary for the CODM to manage the Company under the revised operating segment structure. As a result of this change in operating segments, the Company revised its reportable segments late in the first quarter of 2015. The Company’s revised reportable segments are: (i) Completion Services, (ii) Well Support Services and (iii) Other 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. As a result of the revised reportable segment structure, the Company has restated the corresponding items of segment information for all periods presented. The following is a brief description of the Company's three reportable segments:

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Completion Services

The Company provides hydraulic fracturing services, cased-hole wireline services, coiled tubing services and other well stimulation services through its Completion Services segment.

Well Support Services

The Company provides rig services, fluid management services and other special well site services through its Well Support Services segment.

Other Services

The Other Services segment is comprised of the Company’s smaller service lines and divisions, including directional drilling services, cementing services, equipment manufacturing and repair, specialty chemical sales and research and technology and Middle Eastern operations; the Company manages several of its vertically integrated business through its research and technology division, including its data acquisition and control instruments provider and recently acquired artificial lift applications provider (See Note 10 - Mergers and Acquisitions for further information about this acquisition). Also included in the Other Services are intersegment eliminations and costs associated with activities of a general corporate nature.

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



	Completion Services			Well Support Services			Other Services			Total
Year Ended December 31, 2015
Revenue from external customers	$	1,216,994		$	455,829		$	76,066		$	1,748,889
Adjusted EBITDA	73,850			72,286			(99,380		)	46,756
Depreciation and amortization	188,941			70,861			16,551			276,353
Operating income (loss)	(816,777		)	(1,266		)	(280,279		)	(1,098,322		)
Capital expenditures	91,392			34,974			39,955			166,321
As of December 31, 2015
Total assets	$	1,066,946		$	850,725		$	315,235		$	2,232,906
Goodwill	—			307,677			—			307,677
Year Ended December 31, 2014
Revenue from external customers	$	1,581,712		$	—		$	26,232		$	1,607,944
Adjusted EBITDA	344,742			—			(91,796		)	252,946
Depreciation and amortization	101,554			—			6,591			108,145
Operating income (loss)	243,171			—			(119,427		)	123,744
Capital expenditures	286,083			—			21,515			307,598
As of December 31, 2014
Total assets	$	1,400,183		$	—		$	212,563		$	1,612,746
Goodwill	206,465			—			13,488			219,953
Year Ended December 31, 2013
Revenue from external customers	$	1,058,014		$	—		$	12,308		$	1,070,322
Adjusted EBITDA	254,680			—			(64,051		)	190,629
Depreciation and amortization	73,279			—			1,424			74,703
Operating income (loss)	180,201			—			(65,986		)	114,215
Capital expenditures	146,173			—			5,637			151,810
As of December 31, 2013
Total assets	$	1,002,417		$	—		$	129,883		$	1,132,300
Goodwill	191,794			—			14,004			205,798

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Management evaluates 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 segment’s performance. In addition, management believes that the disclosure of Adjusted EBITDA as a measure of each 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 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 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, to 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, 2015, 2014 and 2013, and on a reportable segment basis for the years ended December 31, 2015, 2014 and 2013.



	Years Ended December 31,
	2015			2014			2013
Adjusted EBITDA	$	46,756		$	252,946		$	190,629
Interest expense, net	(82,086		)	(9,840		)	(6,550		)
Income tax benefit (expense)	299,093			(45,679		)	(41,313		)
Depreciation and amortization	(276,353		)	(108,145		)	(74,703		)
Impairment expense	(791,807		)	—			—
Other income (expense), net	8,773			598			53
Gain (loss) on disposal of assets	544			17			(527		)
Immaterial accounts payable accrual correction	13,190			—			—
Transaction costs	(42,662		)	(20,159		)	(306		)
Severance, facility closures and other	(5,849		)	(35		)	(8		)
Customer settlement/bad debt write-off	(7,997		)	—			—
Incremental insurance reserve	(3,035		)	—			—
Insurance settlement	—			(880		)	—
Inventory write-down	(31,109		)	—			(870		)
Net income (loss)	$	(872,542	)	$	68,823		$	66,405

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Year Ended December 31, 2015
	Completion Services			Well Support Services			Other Services			Total
Adjusted EBITDA	$	73,850		$	72,286		$	(99,380	)	$	46,756
Interest expense, net	(32		)	—			(82,054		)	(82,086		)
Income tax benefit (expense)	—			—			299,093			299,093
Depreciation and amortization	(188,941		)	(70,861		)	(16,551		)	(276,353		)
Impairment expense	(697,480		)	—			(94,327		)	(791,807		)
Other income (expense), net	272			(362		)	8,863			8,773
(Gain) loss on disposal of assets	747			—			(203		)	544
Immaterial accounts payable accrual correction	13,190			—			—			13,190
Transaction costs	—			—			(42,662		)	(42,662		)
Severance, facility closures and other	(2,376		)	(1,752		)	(1,721		)	(5,849		)
Customer settlement/bad debt write-off	(6,747		)	(1,250		)	—			(7,997		)
Incremental insurance reserve	(2,810		)	311			(536		)	(3,035		)
Inventory write-down	(6,210		)	—			(24,899		)	(31,109		)
Net income (loss)	$	(816,537	)	$	(1,628	)	$	(54,377	)	$	(872,542	)



	Year Ended December 31, 2014
	Completion Services			Well Support Services		Other Services			Total
Adjusted EBITDA	$	344,742		$	—	$	(91,796	)	$	252,946
Interest expense, net	(118		)	—		(9,722		)	(9,840		)
Income tax benefit (expense)	—			—		(45,679		)	(45,679		)
Depreciation and amortization	(101,554		)	—		(6,591		)	(108,145		)
Other income (expense), net	277			—		321			598
(Gain) loss on disposal of assets	17			—		—			17
Acquisition-related costs	—			—		(20,159		)	(20,159		)
Severance, facility closures and other	(35		)	—		—			(35		)
Insurance settlement	—			—		(880		)	(880		)
Net income (loss)	$	243,329		$	—	$	(174,506	)	$	68,823



	Year Ended December 31, 2013
	Completion Services			Well Support Services		Other Services			Total
Adjusted EBITDA	$	254,680		$	—	$	(64,051	)	$	190,629
Interest expense, net	(159		)	—		(6,391		)	(6,550		)
Income tax benefit (expense)	—			—		(41,313		)	(41,313		)
Depreciation and amortization	(73,279		)	—		(1,424		)	(74,703		)
Other income (expense), net	224			—		(171		)	53
(Gain) loss on disposal of assets	(527		)	—		—			(527		)
Acquisition-related costs	—			—		(306		)	(306		)
Severance, facility closures and other	(8		)	—		—			(8		)
Inventory write-down	(870		)	—		—			(870		)
Net income (loss)	$	180,061		$	—	$	(113,656	)	$	66,405

Note 12 – Quarterly Financial Data (unaudited)

C&J ENERGY SERVICES LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summarized quarterly financial data for the years ended December 31, 2015 and 2014 are presented below (in thousands, except per share amounts).



	Quarters Ended
	March 31, 2015			June 30, 2015			September 30, 2015			December 31, 2015
Revenue	$	401,216		$	511,165		$	427,497		$	409,011
Operating loss	(30,202		)	(77,350		)	(493,338		)	(497,433		)
Loss before income taxes	(35,556		)	(99,477		)	(524,378		)	(512,224		)
Net loss	(30,663		)	(65,121		)	(455,016		)	(321,742		)
Net loss per common share:
Basic	$	(0.51	)	$	(0.56	)	$	(3.89	)	$	(2.75	)
Diluted	$	(0.51	)	$	(0.56	)	$	(3.89	)	$	(2.75	)



	Quarters Ended
	March 31, 2014		June 30, 2014		September 30, 2014		December 31, 2014
Revenue	$	316,537	$	367,921	$	439,978	$	483,508
Operating income	20,908		20,060		42,011		40,765
Income before income taxes	19,325		18,077		39,439		37,661
Net income	11,588		11,108		23,816		22,311
Net income per common share:
Basic	$	0.22	$	0.21	$	0.44	$	0.41
Diluted	$	0.21	$	0.20	$	0.42	$	0.40

Note 13 – Subsequent Events

On February 1, 2016, the Company’s shareholders approved the Second Amendment (the “Second Amendment”) to the C&J Energy Services 2015 Long Term Incentive Plan (the “Plan”), which provided for (i) an increase of 6.0 million common shares that may be issued under the Plan, (ii) an increase of 3.0 million common shares in the per participant annual limit, from 2.0 million to 5.0 million, that may be awarded under the Plan and (iii) an increase of $5.0 million in the per-participant annual limit on the fair market value of certain awards designated to be paid only in cash or the settlement of which is not based on a number of common shares granted under the Plan, from $5.0 million to $10.0 million.

During the first quarter of 2016 and as of February 23, 2016, the Company made additional draws under its Revolving Credit Facility totaling $130.0 million. As a result of these incremental draws, as of February 23, 2016, the Company had a cash balance of $93.6 million and $251.0 million in borrowings outstanding under its Revolving Credit Facility with $36.4 million of additional availability for borrowing based on $300.0 million of Revolver availability in accordance with the Collateral Coverage Covenant.

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, 2015.

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, 2015, 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, 2015. 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.

KPMG LLP, the Company’s independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2015. Their report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015, is included in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

Changes in Internal Controls over Financial Reporting. 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, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference to our definitive proxy statement for our 2016 Annual Meeting of Shareholders 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, 2015.

Item 11. Executive Compensation

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

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth certain information regarding our equity compensation plans as of December 31, 2015.



Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (A)⁽¹⁾	Weighted-average exercise price of outstanding options, warrants and rights (B)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in Column (A)) (C)⁽²⁾⁽³⁾
Equity compensation plans approved by security holders⁽⁴⁾	5,119,318	$	11.82	3,667,440
Equity compensation plans not approved by security holders	—	—		—
Total	5,119,318	$	11.82	3,667,440

(1)

Consists of (i) 897,700 non-qualified stock options issued and outstanding under the C&J Energy Services Ltd. 2006 Stock Option Plan (the “2006 Plan”), (ii) 3,959,108 non-qualified stock options issued and outstanding under the C&J Energy Services Ltd. 2010 Stock Option Plan (the “2010 Plan”), (iii) 73,766 non-qualified stock options issued and outstanding under the C&J Energy Services Ltd. 2012 Long-Term Incentive Plan (the “2012 LTIP”, and together with the 2006 Plan and the 2010 Plan, the "Prior Plans") and 188,744 non-qualified stock options issued and outstanding under the C&J Energy Services 2015 Long Term Incentive Plan (as amended to date, the “2015 LTIP”)


(2)	Also excluded are 663,936 restricted shares issued and outstanding under the 2012 LTIP and 2,607,168 restricted shares issued and outstanding under the 2015 LTIP.

(3)

The number of common shares available for issuance under the 2015 LTIP is subject to adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, stock dividend, stock split or reverse stock 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 may also increase due to the termination of an award granted under the 2015 LTIP or the Prior Plans by expiration, forfeiture, cancellation or otherwise without the issuance of the common shares.

(4)

The 2015 LTIP was approved and adopted effective as of March 23, 2015, contingent upon the consummation of the Merger. The 2015 LTIP served as an assumption of the 2012 LTIP, including the sub-plan titled the C&J International Middle East FZCO Phantom Equity Arrangement, with certain non-material revisions made and no increase in the number of shares remaining available for issuance under the 2012 LTIP. No additional awards will be granted under

the Prior Plans. See Note 5 - Share-Based Compensation in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information regarding these equity compensation plans.

The remaining information required by this item is incorporated by reference in our definitive proxy statement for our 2016 Annual Meeting of Shareholders 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, 2015.

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

Item 14. Principal Accounting Fees and Services

100

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		Agreement and Plan of Merger, dated as of June 25, 2014, by and among Nabors Industries Ltd., Nabors Red Lion Limited and C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 2.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on July 1, 2014 (File No. 001-35255)).
2.2		Amendment No. 1 to the Agreement and Plan of Merger, dated as of February 6, 2015, by and between C&J Energy Services, Inc., Nabors Industries Ltd., Nabors Red Lion Limited, CJ Holding Co. and Nabors CJ Merger Co. (incorporated herein by reference to Exhibit 10.2 on Current Report on Form 8-K, filed on February 9, 2015 (File No. 001-35255)).
2.3		Separation Agreement by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 2.2 to Nabors Red Lion Limited’s Registration Statement on Form S-4/A, dated February 12, 2015 (Registration No. 333-199004))
2.4		Amendment No. 1 to the Separation Agreement, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 2.5 to Nabors Red Lion Limited’s Registration Statement on Form S-4/A, dated February 12, 2015 (Registration No. 333-199004))
2.5		Joinder Agreement by and among Nabors Industries Ltd., Nabors Red Lion Limited, C&J Energy Services, Inc., Nabors CJ Merger Co., and CJ Holding Co. (incorporated herein by reference to Exhibit 2.3 to Nabors Red Lion Limited’s Registration Statement on Form S-4/A, dated December 19, 2014 (Registration No. 333-199004)).
3.1		Memorandum of Association of Nabors Red Lion Limited (incorporated herein by reference to Exhibit 3.1 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004))
3.2		Amended and Restated Bye-laws of C&J Energy Services Ltd., dated March 24, 2015. (incorporated herein by reference to Exhibit 3.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
4.1		Form of Restricted Share Agreement for Certain Executive Officers with C&J Employment Agreements, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.10 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.2		Form of Restricted Share Agreement for Certain Executive Officers with New Employment Agreements, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.11 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.3		Form of Restricted Share Agreement for Certain Executive Officers with Assumed Employment Agreements, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.12 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).

101



4.4		Form of Restricted Share Agreement with Restrictive Covenants, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.13 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.5		Form of Restricted Share Agreement with Limited Covenants, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.14 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).



4.6		Form of Restricted Share Agreement for Non-Employee Directors, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.15 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404).
4.7		Form of Performance-Based Restricted Share Agreement, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.16 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.8		Form of Nonqualified Share Option Agreement for Replacement Awards, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.17 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.9		Form of Restricted Share Agreement for Replacement Awards (U.S. Employee Form #1), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.18 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.10		Form of Restricted Share Agreement for Replacement Awards (U.S. Employee Form #2), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.19 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.11		Form of Restricted Share Agreement for Replacement Awards (U.S. Employee Form #3), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.20 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.12		Form of Restricted Share Agreement for Replacement Awards (U.S. Employee Form #4), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.21 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.13		Form of Restricted Share Agreement for Replacement Awards (Canadian Employee Form #1), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.22 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.14		Form of Restricted Share Agreement for Replacement Awards (Canadian Employee Form #2), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.23 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.15		Form of Restricted Share Agreement for Replacement Awards (Canadian Employee Form #3), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.24 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.16		Form of Restricted Share Agreement for Replacement Awards (Canadian Employee Form #4), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.25 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.17		Form of Participation Agreement for C&J International Middle East FZCO Phantom Equity Arrangement, a sub-plan of the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.18 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on August 10, 2015 (File No. 000-55404)).
4.18		Form of Common Share Certificate of Nabors Red Lion Limited (incorporated herein by reference to Exhibit 3.4 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated February 12, 2015 (Registration No. 333-199004))



10.1		Credit Agreement, dated as of March 24, 2015, among C&J Energy Services Ltd., CJ Lux Holdings S.à r.l., CJ Holding Co, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Citibank, N.A., as Syndication Agent and Documentation Agent, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on March 30, 2015 (File No. 000-55404)).

102



10.2		First Amendment to Credit Agreement, dated as of March 24, 2015, among C&J Energy Services Ltd., CJ Lux Holdings S.à r.l., CJ Holding Co, the guarantors party thereto, Bank of America, N.A., as Administrative Agent, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.2 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on March 30, 2015 (File No. 000-55404)).
10.3		Waiver and Second Amendment to Credit Agreement, dated as of September 29, 2015, among C&J Energy Services Ltd., CJ Lux Holdings S.à r.l., CJ Holding Co, the guarantors party thereto, Bank of America, N.A., as Administrative Agent, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on September 30, 2015 (File No. 000-55404)).
10.4		Third Amendment (Refinancing Amendment) to Credit Agreement, dated as of September 29, 2015, among C&J Energy Services Ltd., CJ Lux Holdings S.à r.l., CJ Holding Co, the guarantors party thereto, Bank of America, N.A., as Administrative Agent, and the other lenders party thereto(incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on September 30, 2015 (File No. 000-55404)).
10.5+		C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.7 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.6+		First Amendment to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on June 8, 2015 (File No. 000-55404)).
10.7+		Second Amendment to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on February 1, 2016 (File No. 000-55404)).
10.5		Employee Benefits Agreement, dated as of March 24, 2015, by and among C&J Energy Services, Inc., Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.6		Tax Matters Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.2 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.7		Global Alliance Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.3 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.8		Registration Rights Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.4 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.9		Transition Services Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.5 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.10		Transition Services Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.6 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.11		Amendment No. 1 dated as of June 30, 2015 to the Transition Services Agreement dated as of March 24, 2015 is by and between Nabors Industries Ltd., a Bermuda exempted company, and C&J Energy Services Ltd. (formerly known as Nabors Red Lion Limited), a Bermuda exempted company (incorporated herein by reference to Exhibit 10.19 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on August 10, 2015 (File No. 000-55404)).
10.12+		Employment Agreement by and between Nabors Red Lion Limited and Josh Comstock (incorporated herein by reference to Exhibit 10.6 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004).
10.13+		Employment Agreement by and between Nabors Red Lion Limited and Randy McMullen (incorporated herein by reference to Exhibit 10.8 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004)).

103



10.14+		Employment Agreement by and between Nabors Red Lion Limited and Donald J. Gawick (incorporated herein by reference to Exhibit 10.7 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004)).
10.15+		Employment Agreement by and between Nabors Red Lion Limited and Theodore R. Moore (incorporated herein by reference to Exhibit 10.9 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004))
10.16+		Employment Agreement by and between Nabors Red Lion Limited and James H. Prestidge, Jr. (incorporated herein by reference to Exhibit 10.10 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004))
* 21.1		List of Subsidiaries of C&J Energy Services, Inc.

*23.1		Consent of KPMG LLP

* 23.2		Consent of UHY 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

104

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 25th day of February, 2016.




C&J Energy Services Ltd.

By:		/s/ Randall C. McMullen, Jr.
		Randall C. McMullen, Jr.
		President, Chief Financial Officer and Director
		(Principal Financial Officer)


By:		/s/ Brian Patterson
		Brian Patterson
		Corporate Secretary
		(Duly Authorized 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.

105




Signatures and Capacities		Date

By:	/s/ Joshua E. Comstock	February 26, 2016
	Joshua E. Comstock, Chairman and Chief Executive Officer
	(Principal Executive Officer)

By:	/s/ Randall C. McMullen, Jr.	February 26, 2016
	Randall C. McMullen, Jr., President, Chief Financial Officer and Director
	(Principal Financial Officer)

By:	/s/ Mark C. Cashiola	February 26, 2016
	Mark C. Cashiola, Vice President and Chief Accounting Officer
	(Principal Accounting Officer)

By:	/s/ Shel Erikson	February 26, 2016
	Shel Erikson, Director

By:	/s/ William Restrepo	February 26, 2016
	William Restrepo, Director

By:	/s/ Michael Roemer	February 26, 2016
	Michael Roemer, Director

By:	/s/ H. H. “Tripp” Wommack, III	February 26, 2016
	H. H. “Tripp” Wommack, III, Director

106

EXHIBIT INDEX

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




Exhibit No.		Description of Exhibit.

2.1		Agreement and Plan of Merger, dated as of June 25, 2014, by and among Nabors Industries Ltd., Nabors Red Lion Limited and C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 2.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on July 1, 2014 (File No. 001-35255)).
2.2		Amendment No. 1 to the Agreement and Plan of Merger, dated as of February 6, 2015, by and between C&J Energy Services, Inc., Nabors Industries Ltd., Nabors Red Lion Limited, CJ Holding Co. and Nabors CJ Merger Co. (incorporated herein by reference to Exhibit 10.2 on Current Report on Form 8-K, filed on February 9, 2015 (File No. 001-35255)).
2.3		Separation Agreement by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 2.2 to Nabors Red Lion Limited’s Registration Statement on Form S-4/A, dated February 12, 2015 (Registration No. 333-199004))
2.4		Amendment No. 1 to the Separation Agreement, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 2.5 to Nabors Red Lion Limited’s Registration Statement on Form S-4/A, dated February 12, 2015 (Registration No. 333-199004))
2.5		Joinder Agreement by and among Nabors Industries Ltd., Nabors Red Lion Limited, C&J Energy Services, Inc., Nabors CJ Merger Co., and CJ Holding Co. (incorporated herein by reference to Exhibit 2.3 to Nabors Red Lion Limited’s Registration Statement on Form S-4/A, dated December 19, 2014 (Registration No. 333-199004)).
3.1		Memorandum of Association of Nabors Red Lion Limited (incorporated herein by reference to Exhibit 3.1 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004))
3.2		Amended and Restated Bye-laws of C&J Energy Services Ltd., dated March 24, 2015. (incorporated herein by reference to Exhibit 3.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
4.1		Form of Restricted Share Agreement for Certain Executive Officers with C&J Employment Agreements, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.10 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.2		Form of Restricted Share Agreement for Certain Executive Officers with New Employment Agreements, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.11 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.3		Form of Restricted Share Agreement for Certain Executive Officers with Assumed Employment Agreements, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.12 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.4		Form of Restricted Share Agreement with Restrictive Covenants, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.13 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.5		Form of Restricted Share Agreement with Limited Covenants, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.14 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).

107



4.6		Form of Restricted Share Agreement for Non-Employee Directors, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.15 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404).
4.7		Form of Performance-Based Restricted Share Agreement, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.16 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.8		Form of Nonqualified Share Option Agreement for Replacement Awards, pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.17 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.9		Form of Restricted Share Agreement for Replacement Awards (U.S. Employee Form #1), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.18 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.10		Form of Restricted Share Agreement for Replacement Awards (U.S. Employee Form #2), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.19 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.11		Form of Restricted Share Agreement for Replacement Awards (U.S. Employee Form #3), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.20 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.12		Form of Restricted Share Agreement for Replacement Awards (U.S. Employee Form #4), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.21 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.13		Form of Restricted Share Agreement for Replacement Awards (Canadian Employee Form #1), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.22 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.14		Form of Restricted Share Agreement for Replacement Awards (Canadian Employee Form #2), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.23 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.15		Form of Restricted Share Agreement for Replacement Awards (Canadian Employee Form #3), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.24 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.16		Form of Restricted Share Agreement for Replacement Awards (Canadian Employee Form #4), pursuant to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.25 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on May 11, 2015 (File No. 000-55404)).
4.17		Form of Participation Agreement for C&J International Middle East FZCO Phantom Equity Arrangement, a sub-plan of the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.18 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on August 10, 2015 (File No. 000-55404)).
4.18		Form of Common Share Certificate of Nabors Red Lion Limited (incorporated herein by reference to Exhibit 3.4 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated February 12, 2015 (Registration No. 333-199004))



10.1		Credit Agreement, dated as of March 24, 2015, among C&J Energy Services Ltd., CJ Lux Holdings S.à r.l., CJ Holding Co, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Citibank, N.A., as Syndication Agent and Documentation Agent, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on March 30, 2015 (File No. 000-55404)).
10.2		First Amendment to Credit Agreement, dated as of March 24, 2015, among C&J Energy Services Ltd., CJ Lux Holdings S.à r.l., CJ Holding Co, the guarantors party thereto, Bank of America, N.A., as Administrative Agent, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.2 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on March 30, 2015 (File No. 000-55404)).

108



10.3		Waiver and Second Amendment to Credit Agreement, dated as of September 29, 2015, among C&J Energy Services Ltd., CJ Lux Holdings S.à r.l., CJ Holding Co, the guarantors party thereto, Bank of America, N.A., as Administrative Agent, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on September 30, 2015 (File No. 000-55404)).
10.4		Third Amendment (Refinancing Amendment) to Credit Agreement, dated as of September 29, 2015, among C&J Energy Services Ltd., CJ Lux Holdings S.à r.l., CJ Holding Co, the guarantors party thereto, Bank of America, N.A., as Administrative Agent, and the other lenders party thereto(incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on September 30, 2015 (File No. 000-55404)).
10.5+		C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.7 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.6+		First Amendment to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on June 8, 2015 (File No. 000-55404)).
10.7+		Second Amendment to the C&J Energy Services 2015 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K, filed on February 1, 2016 (File No. 000-55404)).
10.5		Employee Benefits Agreement, dated as of March 24, 2015, by and among C&J Energy Services, Inc., Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.6		Tax Matters Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.2 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.7		Global Alliance Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.3 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.8		Registration Rights Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.4 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.9		Transition Services Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.5 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.10		Transition Services Agreement, dated as of March 24, 2015, by and between Nabors Industries Ltd. and Nabors Red Lion Limited (incorporated herein by reference to Exhibit 10.6 to C&J Energy Services Ltd.’s Current Report on Form 8-K12G3, filed on March 25, 2015 (File No. 000-55404)).
10.11		Amendment No. 1 dated as of June 30, 2015 to the Transition Services Agreement dated as of March 24, 2015 is by and between Nabors Industries Ltd., a Bermuda exempted company, and C&J Energy Services Ltd. (formerly known as Nabors Red Lion Limited), a Bermuda exempted company (incorporated herein by reference to Exhibit 10.19 to C&J Energy Services Ltd.’s Quarterly Report on Form 10-Q, filed on August 10, 2015 (File No. 000-55404)).
10.12+		Employment Agreement by and between Nabors Red Lion Limited and Josh Comstock (incorporated herein by reference to Exhibit 10.6 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004).
10.13+		Employment Agreement by and between Nabors Red Lion Limited and Randy McMullen (incorporated herein by reference to Exhibit 10.8 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004)).
10.14+		Employment Agreement by and between Nabors Red Lion Limited and Donald J. Gawick (incorporated herein by reference to Exhibit 10.7 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004)).

109



10.15+		Employment Agreement by and between Nabors Red Lion Limited and Theodore R. Moore (incorporated herein by reference to Exhibit 10.9 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004))
10.16+		Employment Agreement by and between Nabors Red Lion Limited and James H. Prestidge, Jr. (incorporated herein by reference to Exhibit 10.10 to Nabors Red Lion Limited’s Registration Statement on Form S-4, dated September 29, 2014 (Registration No. 333-199004))
* 21.1		List of Subsidiaries of C&J Energy Services, Inc.

*23.1		Consent of KPMG LLP

* 23.2		Consent of UHY 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

110

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (do not check if a smaller reporting company)

Smaller reporting company