C&J Energy Services, Inc. - FORM 8-K/A - EX-99.1

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EX-23.1 - EX-23.1 - C&J Energy Services, Inc.	d54761dex231.htm
EX-23.2 - EX-23.2 - C&J Energy Services, Inc.	d54761dex232.htm
8-K/A - 8-K/A - C&J Energy Services, Inc.	d54761d8ka.htm

Exhibit 99.1

The disclosure contained in this exhibit has been derived from the Annual Report on Form 10-K of C&J Energy Services, Inc. for the year ended December 31, 2014, which was filed with the SEC prior to the consummation of the Merger (as defined below). As a result of the consummation of the Merger, C&J Energy Services, Inc. is a private wholly owned subsidiary of C&J Energy Services Ltd. The disclosure contained in this exhibit should be read in conjunction with the corresponding disclosure contained in the Annual Report on Form 10-K of Nabors Red Lion Limited for the year ended December 31, 2014. Unless the context indicates otherwise, as used herein, the terms “we”, “us”, “our”, “the Company”, “C&J”, or like terms refer to C&J Energy Services, Inc. and its subsidiaries prior to the closing of the Merger (the “Effective Time”).

Due to the transformative nature of the Merger, the Company’s chief operating decision maker (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 commencing with 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, specifically 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 in this section for all periods presented.

BUSINESS

General Description of Our Business

We are an independent provider of premium hydraulic fracturing, coiled tubing, cased-hole wireline, pumpdown, and other complementary services with a focus on complex, technically demanding well completions. These core services are provided to oil and natural gas exploration and production companies throughout the United States. During the second quarter of 2014, we introduced our directional drilling services line to customers as a new service offering, and we are investing in the growth of this business in key U.S. markets. As a result of the development of our strategic initiatives and acquisitions during 2013, we expanded our business to blend and supply specialty chemicals for completion and production services, including the fluids used in our hydraulic fracturing operations, and we also manufacture and sell data acquisition and control systems and provide our proprietary, in-house manufactured downhole tools and related directional drilling technology. We utilize these products in our day-to-day operations, and we also provide these products to third-party customers in the energy services industry. These strategic initiatives and acquisitions are described in more detail under “Strategic Initiatives and Growth Strategy – Service Line Diversification, Vertical Integration & Technological Advancement.” In addition to our suite of completion, stimulation and production enhancement products and services, we manufacture, repair and refurbish equipment and provide parts and supplies for third-party companies in the energy services industry, as well as to fulfill our internal needs.

Our principal executive offices are located at 3990 Rogerdale Rd, Houston, Texas 77042, and our main telephone number is (713) 325-6000. We operate in some of the most active domestic onshore basins with facilities across the United States, including in Texas, Oklahoma, New Mexico, Colorado, Utah, North Dakota, West Virginia and Pennsylvania. In 2013, we opened our first international office in Dubai with a goal of becoming a significant, long term provider of multiple services throughout the Middle East.

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 Form 8-K/A or any other report that we may file with or furnish to the SEC.

The Combination Transactions

Effective as of March 24, 2015, 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”).

Effective upon the Effective Time, shares of common stock 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 New York Stock Exchange under the ticker “CJES.” 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.

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 completion of the Merger and results from prior periods may not be meaningful.

As a result of the Merger, 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. 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.

Strategic Initiatives and Growth Strategy

Expansion of Core Service Lines

During 2014, we continued to focus on growing our core service lines through the expansion of our assets, customer base and geographic reach, both domestically and internationally.

On the domestic front, over the course of 2014, we steadily grew our business and gained market share in each of our service lines through the deployment of incremental capacity across our asset base and targeted sales and marketing efforts to expand our customer base. We strengthened our presence in areas with high customer demand within our existing geographic footprint and also introduced our coiled tubing and wireline operations (which includes our pumpdown services) to new markets. Our operational and financial results over the course of 2014 were driven by a strong performance across our core service lines, as we capitalized on high activity and service intensity levels, having strategically positioned ourselves for the anticipated increase in completion activity entering 2014. However, U.S. domestic drilling and completion activities decreased towards the end of the fourth quarter as a result of rapidly declining commodity prices, as well as the typical year-end seasonal slowdown and disruption due to inclement weather.

With respect to our hydraulic fracturing operations, we deployed over 120,000 incremental hydraulic horsepower capacity during the year to take advantage of the rise in service-intensive completion activity that we experienced through most of 2014. Due to strategic planning and the flexibility and control provided by our in-house manufacturing capabilities, we were able to put these fleets to work with high activity operators immediately upon taking delivery of the equipment. We also grew our coiled tubing and wireline operations, deploying incremental equipment to strengthen our presence in highly active basins, and we gained market share in some of our newer operating regions. During the third quarter of 2014, we opened our first office in Wyoming, where we are now offering wireline services, as well as our directional drilling services, which we introduced to customers as a new service offering during the second quarter of 2014. Our directional drilling services line is described in more detail under “– Service Line Diversification, Vertical Integration & Technological Advancement.” In addition to organic growth, in May 2014, we acquired Tiger Casedhole Services, Inc. (“Tiger”), a leading provider of cased-hole wireline, logging, perforating, pipe recovery and tubing-conveyed perforating services in California. The acquisition of Tiger increased our existing wireline capabilities and provides a presence on the U.S. West Coast, which was a new market for C&J.

With the sharp decline in commodity prices in the second half of 2014 and extending into 2015, we are experiencing a slowdown in activity across our customer base, which in turn has increased competition and put downward pressure on pricing for our services. As we move through 2015, we recognize the uncertain market conditions will be challenging for our industry. Although the severity and extent of this downturn is uncertain, absent a significant recovery in commodity prices, we expect that activity and pricing levels will continue to decline. In response to this difficult environment, we are focused on maintaining utilization, preserving our competitive position and protecting market share by continuing to deliver differentiated value to our customers. As part of our strategy, we will continue to target high volume, high efficiency customers with service intensive, 24-hour work, which is where we believe that we can differentiate our services from our competitors. As our customers seek to reduce pricing in response to depressed commodity prices, we have been diligent in identifying ways to increase efficiencies and lower our operating costs. Although we believe we are prepared for the challenges that lie ahead, the weak activity and pricing environment characterizing this downturn will negatively impact our financial and operating results.

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contract. Due to the size of this first project and the additional costs associated with establishing operations overseas, we do not expect to generate financial returns during this initial phase. Additionally, there is no guarantee that we will be able to obtain additional work with this customer beyond this provisional contract. However, we believe that this is a valuable opportunity to demonstrate our services outside of the United States. We are optimistic that our efforts can lead, over time, to a long-term relationship and additional opportunities with this new customer. We also hope that by demonstrating our capabilities in the region we may be able to secure opportunities with other potential customers in the Middle East.

Service Line Diversification, Vertical Integration & Technological Advancement

During 2014, we further advanced our ongoing strategic initiatives designed to strengthen, expand and diversify our business. As we continue to execute our long-term growth strategy, we remain focused on service line diversification, vertical integration and technological advancement. Our continued investment in our strategic initiatives resulted in increasing capital expenditures and additional costs during 2014, and we expect that our costs and expenses will continue to increase as we further develop these projects. However, over the course of 2015, we expect to generate meaningful cost savings from a number of these projects. Further, we believe that these investments will yield significant financial returns, as well as significant cost savings to us, over the long term. Our strategic initiatives have not contributed significant third-party revenue to date, and we do not expect that any will contribute meaningful third-party revenue over the near term. If this current industry downturn and depressed pricing environment for crude oil 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.

Our key strategic initiatives in 2014 included the following:

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Directional Drilling Services. 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 leasing them to third-party customers. Additionally, during the second quarter of 2014, we introduced our new directional drilling services line to customers as a new service offering.

Although our directional drilling business is still in the early stages, we are now offering directional drilling services to customers in Wyoming, North Dakota and Utah as well as in Texas, with plans to commence operations in Oklahoma during 2015. Initial customer feedback has been positive, although, demand has been negatively impacted by the reduction in drilling and completion activities throughout the industry due to the decline in commodity prices. We do not expect this service line to provide any meaningful contribution to revenue in the near term, especially in light of current market conditions. However, we believe that it has significant potential over the long-term, and we intend to continue investing in its growth. Although not at the outset, our goal is that, over time, our directional drilling services will be provided exclusively using our integrated downhole tools and directional drilling technology. Through our research and technology division, we are developing differentiated, cost-effective directional drilling products, including additional models of our drilling motors.

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Specialty Chemicals Business. In 2013, we began organically developing a specialty chemicals 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. In an effort to drive cost savings from intercompany purchases, we expanded the capabilities of this business during 2014, including the capability to blend guar slurry for hydraulic fracturing operations. We also focused on growing strategic third-party sales from this business, although this business has not, and we do not expect that in the near term it will, provide any meaningful contribution to revenue. We intend to continue growing this business with the long-term goal of becoming a large-scale supplier of these products to the oil and gas industry.

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Mobile Data Systems. In December 2013, we acquired a manufacturer of data acquisition and control instruments that are used in our hydraulic fracturing operations. In September 2014, we deployed the first of our hydraulic fracturing equipment to include our proprietary data control systems. We believe that the enhanced functionality and cost savings provided by satisfying one more of our equipment needs in-house will yield strong returns on our investment over the long-term. In addition to achieving cost savings through intercompany purchases, we are also selling these products to third-party energy services companies, although this business has not, and we do not expect that in the near term it will, provide any meaningful contribution to revenue.

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started in 2013, and vertical integration plan, we launched our new directional drilling services line and began to incorporate our proprietary data control systems in our hydraulic fracturing equipment. We also began to use our proprietary perforating gun system, which is the result of a collaborative effort between our operations and technology teams, in our wireline operations. We believe these perforating guns will enhance the quality, reliability and safety of our wireline operations. Additionally, we are manufacturing them in-house, which is expected to generate significant costs savings over the long term.

We believe that one of the strategic benefits that our research and technology division provides us is the ability to develop and implement new technologies and enhancements and respond to changes in customers’ requirements and industry demand. Our equipment manufacturing division provides another platform to integrate our strategic initiatives, implement technological developments and enhancements and capture additional cost savings. We will continue to make further investments in technological advancement, as we are confident that our efforts will yield significant returns, efficiencies and meaningful cost savings to us over the long term.

Our Operating Segments

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 during 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. The Company has recast the segment information below to reflect the new reportable segment structure in order to conform to the current year presentation. The following is a description of the reportable segments.

Completion Services

Our Completion Services segment consists of hydraulic fracturing, coiled tubing, cased-hole wireline and pumpdown services, as well as 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.

Historically, we have reviewed and disclosed asset utilization rates for each of the service lines now within our Completion Service segment. However, given the variance in revenue and profitability from job to job, depending on the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed, our management team has focused on other performance metrics in evaluating the operating and financial performance of our Completion Services segment. Management now 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 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, 2014, revenue from our Completion Services segment was $1.6 billion, representing approximately 98% of our total revenue. Our core service lines that are now included in our Completion Services segment contributed revenue of $1.6 billion, compared with $1.1 billion in the year ended December 31, 2013, which represents a 50% year-over-year increase.

Adjusted EBITDA from this segment for the year ended December 31, 2014 was $345.0 million, compared with $254.2 million of Adjusted EBITDA for the year ended December 31, 2013, which represents a 36% year-over-year increase.

Well Support Services

Our Well Support Services segment, which was acquired as part of the C&P Business, consists of well services, including maintenance, workover and plug and abandonment services, as well as fluid management, rental tool, and salt water disposal services. The majority of revenue for this segment is generated by well services and fluid management services.

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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. Our rig fleet is also used in the process of permanently shutting-in oil or natural 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 natural gas because well operators are required by state regulations to plug wells that are no longer productive.

With respect to our fluid management operations, 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 these services generally correspond to demand for our well service rigs.

At this time we are still reviewing and evaluating our recently acquired Well Support Services operations, and we have not yet identified the most important performance measures for the lines of business within this segment. We are currently focused on Adjusted EBITDA as a key indicator of this segment’s financial condition and operating performance.

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.

Other Services

Our Other Services segment includes smaller service lines from both Legacy C&J and the C&P Business, such as cementing, directional drilling, equipment manufacturing and specialty chemicals supply, as well as our Research & Technology division. Corporate overhead and intersegment eliminations are also included in this Other Services segment.

Our Other Services segment contributed $26.1 million of revenue for the year ended December 31, 2014, representing approximately 2% of our total revenue. Adjusted EBITDA before net interest expense, income taxes, depreciation and amortization, from this segment was ($91.5) million. The Legacy C&J services that are included in the Other Services segment contributed all of the revenue for the year ended December 31, 2014. These services contributed $12.1 million of revenue for the year ended December 31, 2013, which represents a 116% year-over-year increase.

Other Information About Our Business

Geographic Areas

We operate in most of the major oil and natural gas producing regions of the continental United States, including the Permian Basin, Eagle Ford, Bakken and Marcellus Shales. During the years ended December 31, 2012 and 2013, all of our revenue from external customers was derived from the United States, and all of our long-lived assets were located in the United States. During the year ended December 31, 2014, substantially all of our revenue from external customers was derived from the United States, and substantially all of our long-lived assets were located in the United States. However, in the second quarter of 2014 we positioned two of our coiled tubing units in Saudi Arabia to service our first international contract and during the year ended December 31, 2014, we generated $1.0 million, or 0.1% of our consolidated revenue, from coiled tubing operations in Saudi Arabia.

Over the past several years, we have focused on expanding our geographic reach, both domestically and internationally. With respect to our international expansion efforts, during 2014 we continued to invest in the infrastructure needed to support the development of operations in the Middle East. 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.

Due to the size of this first project and the additional costs associated with establishing operations overseas, we do not expect to generate financial returns during this initial phase. Additionally, there is no guarantee that we will be able to obtain additional work with this customer beyond this provisional contract. However, we believe that this is a valuable opportunity to demonstrate our services outside of the United States. We are optimistic that our efforts can lead, over time, to a long-term relationship and additional opportunities with this new 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. For certain risks attendant to our anticipated non-U.S. operations, please read “Risk Factors” in Part I, Item 1A of this Form 10-K.

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Seasonality

Our operations are subject to seasonal factors. Specifically, in the fourth quarter, we typically have experienced a pause by our customers around the holiday season, and activity will slow during the latter part of the year as our customers exhaust their annual capital spending budgets. 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. During the summer months, our operations may be impacted by tropical weather systems.

Sales and Marketing

Our sales and marketing activities relating to our core service lines 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.

With the acquisition of our wireline business in June 2012, we expanded the suite of completion services available to our customers and focused on cross-selling our core service offerings. We believe that our ability to deliver these services without a loss of quality or efficiency differentiates us from our similarly-sized competitors. We have leveraged the broader customer base and geographic reach of our wireline business to introduce our other service lines to new customers as well as into new geographic regions where our wireline business already had a presence. This strategy has worked particularly well for growing our coiled tubing operations in the Marcellus and Bakken Shales over the past several years.

With respect to our hydraulic fracturing operations, over the course of 2013, our exposure to the spot market significantly increased as all but one of our legacy term contracts expired and the remaining contract expired in early 2014. We increased our sales and marketing efforts in response to our new operating environment and we believe we have adapted our strategy to address the challenges of our position. This strategy includes continuing to target customers who focus on horizontal drilling efficiency, service intensive 24-hour operations and multi-well pad drilling.

Customers

Through our Completion Services segment, we serve a diverse group of independent and major oil and gas companies that are active in our core areas of operations across the continental U.S. Due to the short lead time between ordering services and providing services, there is no sales backlog in these core service lines.

The majority of our revenue is generated from our hydraulic fracturing services, which were primarily provided to independent oil and natural gas exploration and production companies in the Eagle Ford Shale and Permian Basin in 2014. Historically, most of our hydraulic fracturing revenue was generated by work provided under six legacy term contracts, which had minimum utilization requirements and favorable pricing terms relative to spot market pricing. Given the nature of these contracts and the limited size of our hydraulic fracturing asset base, our customer concentration has been high. Over the course of 2013, all but one of our legacy term contracts expired, and the remaining contract expired in early 2014. Although the expiration of our legacy term contracts provided an opportunity to work for new customers, we continue to provide a substantial amount of hydraulic fracturing services to certain of our previously contracted customers, so our customer concentration remains high.

The addition of our wireline business in June 2012 expanded our customer base and geographic footprint. Successfully leveraging the broader customer base and geographic reach of our wireline business, we are now providing our coiled tubing, wireline, pressure pumping and related well stimulation and completion services to a diverse group of independent and major oil and gas companies across the continental United States. However, given the significance of our hydraulic fracturing operations to our business, our revenue, earnings and cash flows are substantially dependent upon a concentrated group of customers.

Our top ten customers accounted for approximately 51.1%, 64.6% and 81.0% of our consolidated revenue for the years ended December 31, 2014, 2013 and 2012, respectively. For the year ended December 31, 2014, revenue from Anadarko Petroleum Corporation and Apache Corporation represented 16.4% and 9.6%, respectively, 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. For the year ended December 31, 2012, revenue from Anadarko Petroleum Corporation, Apache Corporation, and Freeport-McMoRan Oil and Gas individually represented 19.1%, 15.6%, 12.9%, respectively, of our consolidated revenue. Other than those listed above, no other customer accounted for more than 10% of our consolidated revenue in 2014, 2013 or 2012. If we were to lose any material customer, we may not be able to redeploy our equipment at similar

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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. We monitor closely the financial condition of our customers, their capital expenditure plans, and other indications of their drilling and completion activities.

The customers served through our equipment manufacturing business are primarily energy services companies. C&J historically has been, and continues to be, the top customer for this business and it did not generate a significant portion of our consolidated revenue for the years ended December 31, 2014, 2013 or 2012.

Industry Overview; Competition and Demand for Our Services

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 natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by 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. The volatility of the oil and gas industry, and the consequent negative impact on the level of exploration, development and production activity and capital expenditures by our customers, has adversely affected, and in the future may adversely affect, the demand for our services. 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. 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 natural 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 natural gas. Oil and natural 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, within the past year, oil prices were as high as $107 per barrel and have been as low as $44 per barrel. Generally, as the supply of these commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural gas price environment, demand for service and maintenance generally decreases as oil and natural gas producers decrease their activity and expenditures. In particular, the demand for drilling, completion and workover services is driven by available investment capital for such activities. When these capital investments decline, our customers’ demand for our services declines. Because the type of services that we offer 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. A prolonged low level of customer activity will adversely affect the demand for our services and our financial condition and results of operations.

At the end of 2014 we saw a pullback in drilling and completion activities in response to commodity price declines and the slowdown has intensified in 2015. We are currently experiencing a decrease in activity across our customer base, which in turn has increased competition and put pressure on pricing for our services. Although the severity and extent of this downturn is uncertain, absent a significant recovery in commodity prices, we expect that activity and pricing levels will continue to decline. In reaction to this challenging environment, we have put a sharp focus on cost management, particularly input costs and labor. In order to offset as much of the pricing concessions as we can, among other things, we are working with our vendors to lower certain input costs. Our priority is on maintaining utilization and we are targeting operators who we believe have some insulation to current market challenges due to attractive acreage, size and hedging profiles, among other factors. We believe that the strategic investments in vertical integration that we have made, and our efforts to lower our cost base and improve our operational capabilities and efficiencies, will help us manage through this down-cycle. Although we believe we are prepared for the challenges that lie ahead, the weak activity and pricing environment characterizing this downturn will negatively impact our financial and operating results over the near term.

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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 hydraulic fracturing services include Halliburton, Schlumberger, Baker Hughes, Calfrac Well Services, Trican, Weatherford International, RPC, Inc., Pumpco, an affiliate of Superior Energy Services, and Frac Tech. Our major competitors for our coiled tubing and other well stimulation services include Halliburton, Schlumberger, Baker Hughes, RPC, Inc. and a significant number of regional businesses. Our major competitors for our wireline services include Schlumberger, Halliburton and Archer.

We believe that the principal competitive factors in the markets that we serve are 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. Additionally, projects 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Industry Trends and Outlook” in this Form 8-K/A for additional discussion of the market challenges within our industry.

Our equipment manufacturing business competes against numerous businesses, many of which are much larger and have greater financial and other resources. Major competitors for well stimulation equipment include Stewart & Stevenson, Enerflow Industries Inc., United Engines Manufacturing (a subsidiary of United Holdings LLC), Dragon Products (a division of Modern Group Inc.), National Oilwell Varco, Inc. and Caterpillar Inc. For our well servicing and coiled tubing and other well stimulation products, our major competitors are National Oilwell Varco, Inc., Stewart & Stevenson, Gardner Denver, and Caterpillar Inc. We believe that our customers base their decisions to purchase equipment based on price, lead time and delivery, quality, and aftermarket parts and service capabilities.

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 from various third-party suppliers, as well as from our equipment manufacturing and specialty chemicals businesses. During the year ended December 31, 2014, 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. 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. 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.

We also purchase materials, products and services from certain related parties. In accordance with the rules and regulations of the SEC, we maintain a “Related Persons Transaction Policy” that provides guidelines for the review of all transactions or arrangements involving the Company and any of our directors (or nominees for director), executive officers, stockholders owning more than 5% of the Company, or any immediate family members of any such person, to determine whether such persons have a direct or indirect material interest in the transaction. Such related persons transactions are also subject to our Code of Conduct and Ethics, which restricts our directors, officers and employees from engaging in any business or conduct or entering into any agreement or arrangement that would give rise to an actual or potential conflict of interest. We have processes for reporting actual or potential conflicts of interests, including related person transactions, under both our Code of Conduct and Ethics and our Related Persons Transactions Policy. We are required to disclose each year in our proxy statement certain transactions between the Company and related persons, as well as our policies concerning related person transactions. For information regarding our related-party suppliers, please see “Transactions with Related Persons – Related Person Transactions” in our definitive proxy statement for the 2015 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act. We expect to file this definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2014.

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Safety

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 quality management training programs, as well as our employee review process. We have comprehensive safety and training programs designed to minimize accidents in the workplace and improve the efficiency of our operations. We believe that our 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 in our Completion Services segment are subject to hazards inherent in the oil and gas industry, including accidents, blowouts, explosions, craterings, fires, oil spills and hazardous materials spills. These conditions can cause:

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personal injury or loss of life;

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damage to, or destruction of, property, equipment, the environment and wildlife; and

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suspension of operations.

In addition, claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims for damages.

Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.

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 general liability insurance coverage of types and amounts that we believe to be customary in the industry, including sudden and accidental pollution insurance. Our sudden and accidental pollution insurance coverage is currently included under general liability, consisting of $1.0 million of underlying coverage for each occurrence, $10.0 million of umbrella coverage for each occurrence and $90.0 million of additional excess coverage for each occurrence. We also maintain insurance for property damage relating to catastrophic events. 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. Our MSAs delineate our and our customer’s respective indemnification obligations with respect to the services we provide. With respect to our Completion Services segment, our MSAs typically provide for knock-for-knock indemnification for all losses, which means that we and our customers assume liability for damages to or caused by 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 typically 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 resulting from our negligent actions, 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.

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The description of insurance policies set forth above is a summary of the 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.

We also maintain a variety of insurance for our Equipment Manufacturing operations that we believe to be customary and reasonable. Other than normal business and contractual risks that are not insurable, our risks are commonly insured and the effect of a loss occurrence is not expected to be significant.

Employees

As of February 13, 2015, we had 3,490 employees. We increased our overall headcount by approximately 40% over the course of 2014 to support the growth of our business. Subject to local market conditions, the additional crew members needed for our Completion Services segment 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

We operate under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, the handling of hazardous materials, the use, management and disposal of certain radioactive materials, the transportation of explosives, the protection of the environment, and motor carrier operations. Regulations concerning equipment certification create an ongoing need for regular maintenance, which is incorporated into our daily operating procedures. Moreover, the oil and gas industry is subject to environmental regulation pursuant to local, state and federal legislation.

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.

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.

Environmental Matters

Our operations are subject to stringent and complex federal, state and local environmental and occupational, health and safety laws and regulations, including those governing the release and/or discharge of materials into the environment or otherwise relating to environmental protection. 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. We believe that we are in substantial compliance with applicable environmental laws and regulations. Further, we do not anticipate that compliance with existing environmental laws and regulations will have a material

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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.

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 that 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 legislation were enacted, 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 offsite 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 (including substances disposed of or released by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), 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. 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.

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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 recently has taken the position that hydraulic fracturing with fluids containing diesel fuel are subject to regulation under the UIC program, specifically as “Class II” UIC wells. We do not utilize diesel fuel in our fracturing services. In addition, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria 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.

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. Also, in May 2014, the EPA published an advanced notice of proposed rulemaking 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.

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. 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.

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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 recordkeeping, and other requirements. 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. 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.

In addition, oil and natural gas production, processing, transmission and storage operations are now subject to regulation under the New Source Performance Standards and National Standards for Emission of Hazardous Air Pollutants programs. These rules require, among other things, the reduction of volatile organic compound (“VOC”) emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” wells must 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. The rule is designed to limit emissions of VOC, sulfur dioxide, and hazardous air pollutants from a variety of sources within natural gas processing plants, oil and natural gas production facilities, and natural gas transmission compressor stations. This rule could require a number of modifications to oil and gas exploration and production operations, including the installation of new equipment. 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 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 GHG emissions from specified GHG sources, including, among others, certain oil and natural gas production facilities, on an annual basis. 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 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 assets and operations.

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Worker Safety

We are also 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.

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

The following discussion and analysis of our financial condition and results of operations 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 Form 8-K.

As discussed under “The Combination Transactions” below, on March 24, 2015, Legacy C&J (as defined below) and the completion and production services business of Nabors Industries Ltd. completed the combination of their respective businesses (the “Transactions”). 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. included in this Current Report on Form 8-K, each of which cover periods prior to the completion of the Transactions, 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 Nabors Red Lion Limited.

Due to the transformative nature of the Transactions, the Company’s chief operating decision maker (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 during with 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. The Company has recast the segment information below to reflect the new reportable segment structure in order to conform to the current year presentation. The following is a description of the reportable segments.

You should read the following discussion and analysis of the Company’s financial condition and results of operations in conjunction with the financial statements and notes thereto, including the historical financial statements of Legacy C&J and the pro forma financial information reflecting the effects of the Transactions, included elsewhere in this Current Report on Form 8-K.

Certain statements and information in this discussion may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These include statements regarding the effects of the Transactions, estimates, expectations, projections, goals, forecasts, assumptions, risks and uncertainties and are typically identified by words or phrases such as “may,” “will,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “target,” “forecast,” and other words and terms of similar meaning. For example, statements regarding future financial performance, future competitive positioning and business synergies, future acquisition cost savings, future accretion to earnings per share, future market demand, future benefits to stockholders, future economic and industry conditions, the transactions (including its benefits, results, and effects), and the attributes of the Transactions and the combined company, are forward-looking statements within the meaning of federal securities laws.

These forward-looking statements are subject to numerous risks and uncertainties, many of which are beyond the control of the Company, which could cause actual benefits, results, effects and timing to differ materially from the results predicted or implied by the statements. These risks and uncertainties include, but are not limited to: potential adverse reactions or changes to business relationships resulting from the completion of the Transactions; competitive responses to the Transactions; costs and difficulties related to the integration of Legacy C&J’s business and operations with Nabors’ completion and production services business and operations; the inability to obtain or delay in obtaining cost savings and synergies from the Transactions; unexpected costs, charges or expenses resulting from the Transactions; the outcome of pending or potential litigation; the inability to retain key personnel; uncertainty of the expected financial performance of the combined company; and any changes in general economic and/or industry specific conditions.

The Combination Transactions

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”).

Overview

We are an independent provider of premium hydraulic fracturing, coiled tubing, cased-hole wireline, pumpdown, and other complementary services with a focus on complex, technically demanding well completions. These core services are provided to oil and natural gas exploration and production companies throughout the United States. During the second quarter of 2014, we introduced our directional drilling services line to customers as a new service offering and we are investing in the growth of this business in key U.S. markets. As a result of the development of our strategic initiatives and acquisitions during 2013, we expanded our business to blend and supply specialty chemicals for completion and production services, including the fluids used in our hydraulic fracturing operations, and we also manufacture and sell data acquisition and control systems and provide our proprietary, in-house manufactured downhole tools and related directional drilling technology. We utilize these products in our day-to-day operations, and we also provide these products to third-party customers in the energy services industry. These strategic initiatives and acquisitions are described in more detail under “Strategic Initiatives and Growth Strategy – Service Line Diversification, Vertical Integration & Technological Advancement.” In addition to our suite of completion, stimulation and production enhancement products and services, we manufacture, repair and refurbish equipment and provide parts and supplies for third-party companies in the energy services industry, as well as to fulfill our internal needs.

Our principal executive offices are located at 3990 Rogerdale Rd, Houston, Texas 77042 and our main telephone number is (713) 325-6000. We operate in some of the most active domestic onshore basins with facilities across the United States, including in Texas, Oklahoma, New Mexico, Colorado, Utah, North Dakota, West Virginia, and Pennsylvania. In 2013, we opened our first international office in Dubai with a goal of becoming a significant, long term provider of multiple services throughout the Middle East.

Strategic Initiatives and Growth Strategy

Expansion of Core Service Lines

During 2014, we continued to focus on growing our core service lines through the expansion of our assets, customer base and geographic reach, both domestically and internationally.

On the domestic front, over the course of 2014 we steadily grew our business and gained market share in each of our service lines through the deployment of incremental capacity across our asset base and targeted sales and marketing efforts to expand our customer base. We strengthened our presence in areas with high customer demand within our existing geographic footprint and also introduced our coiled tubing and wireline operations (which includes our pumpdown services) to new markets. Our operational and financial results over the course of 2014 were driven by a strong performance across our core service lines, as we capitalized on

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high activity and service intensity levels, having strategically positioned ourselves for the anticipated increase in completion activity entering 2014. However, U.S. domestic drilling and completion activities decreased towards the end of the fourth quarter as a result of rapidly declining commodity prices, as well as the typical year-end seasonal slowdown and disruption due to inclement weather.

With respect to our hydraulic fracturing operations, we deployed over 120,000 incremental hydraulic horsepower capacity during the year to take advantage of the rise in service-intensive completion activity that we experienced through most of 2014. Due to strategic planning and the flexibility and control provided by our in-house manufacturing capabilities, we were able to put these fleets to work with high activity operators immediately upon taking delivery of the equipment. We also grew our coiled tubing and wireline operations, deploying incremental equipment to strengthen our presence in highly active basins and we gained market share in some of our newer operating regions. During the third quarter of 2014, we opened our first office in Wyoming, where we are now offering wireline services, as well as our directional drilling services, which we introduced to customers as a new service offering during the second quarter of 2014. Our directional drilling services line is described in more detail under “ – Service Line Diversification, Vertical Integration & Technological Advancement.” In addition to organic growth, in May 2014, we acquired Tiger Casedhole Services, Inc. (“Tiger”), a leading provider of cased-hole wireline, logging, perforating, pipe recovery and tubing-conveyed perforating services in California. The acquisition of Tiger increased our existing wireline capabilities and provides a presence on the U.S. West Coast, which was a new market for C&J.

With respect to our international expansion efforts, during 2014 we continued to invest in the infrastructure needed to support the development of operations in the Middle East. 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. To date, we are continuing to work in Saudi Arabia under this contract. Due to the size of this first project and the additional costs associated with establishing operations overseas, we do not expect to generate financial returns during this initial phase. Additionally, there is no guarantee that we will be able to obtain additional work with this customer beyond this provisional contract. However, we believe that this is a valuable opportunity to demonstrate our services outside of the United States. We are optimistic that our efforts can lead, over time, to a long-term relationship and additional opportunities with this new customer. We also hope that by demonstrating our capabilities in the region we may be able to secure opportunities with other potential customers in the Middle East.

Service Line Diversification, Vertical Integration & Technological Advancement

Our key strategic initiatives in 2014 included the following:

•

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Although our directional drilling business is still in the early stages, we are now offering directional drilling services to customers in Wyoming, North Dakota and Utah as well as in Texas, with plans to commence operations in Oklahoma during 2015. Initial customer feedback has been positive, although demand has been negatively impacted by the reduction in drilling and completion activities throughout the industry due to the decline in commodity prices. We do not expect this service line to provide any meaningful contribution to revenue in the near term, especially in light of current market conditions. However, we believe that it has significant potential over the long-term and we intend to continue investing in its growth. Although not at the outset, our goal is that, over time, our directional drilling services will be provided exclusively using our integrated downhole tools and directional drilling technology. Through our research and technology division, we are developing differentiated, cost-effective directional drilling products, including additional models of our drilling motors.

•

Technological Advancement. Over the course of 2014, we further advanced our research and technology capabilities as we continued to focus on developing innovative, fit-for-purpose solutions designed to reduce costs, increase completion efficiencies, enhance our service capabilities and add value for our customers. As a result of these efforts, in 2014, 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. Through the efforts of our research and technology division, which we started in 2013, and vertical integration plan, we launched our new directional drilling services line and began to incorporate our proprietary data control systems in our hydraulic fracturing equipment. We also began to use our proprietary perforating gun system, which is the result of a collaborative effort between our operations and technology teams, in our wireline operations. We believe these perforating guns will enhance the quality, reliability and safety of our wireline operations. Additionally, we are manufacturing them in-house, which is expected to generate significant costs savings over the long term.

Our Operating Segments

Due to the transformative nature of the Transactions, 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 during 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. The Company has recast the segment information below to reflect the new reportable segment structure in order to conform to the current year presentation. The following is a description of the reportable segments.

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Completion Services

Well Support Services

Maintenance services provided with our rig fleet are generally required throughout the life cycle of an oil or natural 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. The workover services that we provide 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. Our rig fleet is also used in the process of permanently shutting-in oil or natural 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 natural gas because well operators are required by state regulations to plug wells that are no longer productive.

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.

Other Services

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Our Other Services segment contributed $26.1 million of revenue for the year ended December 31, 2014, representing approximately 2% of our total revenue. Adjusted EBITDA before net interest expense, taxes, depreciation and amortization, from this segment was ($91.5) million. The Legacy C&J services that are included in the Other Services segment contributed all of the revenue for the year ended December 31, 2014. These services contributed $12.1 million of revenue for the year ended December 31, 2013, which represents a 116% year-over-year increase.

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 this section in conjunction with the factors described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K 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 natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by 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. The volatility of the oil and gas industry, and the consequent negative impact on the level of exploration, development and production activity and capital expenditures by our customers, has adversely affected, and in the future may adversely affect, the demand for our services. 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.

Entering the fourth quarter of 2013 we saw an increase in activity across our core service lines, partially offset by seasonal declines and inclement weather in many of our operating areas. As we entered 2014, utilization across our core service lines improved, with the most significant increase seen in our hydraulic fracturing business, and completion activity and service intensity levels continued to increase through most of the year. Pricing, however, remained relatively flat, in part due to the continued level of competition in the market.

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this challenging environment, we have put a sharp focus on cost management, particularly input costs and labor. In order to offset as much of the pricing concessions as we can, among other things, we are working with our vendors to lower certain input costs. Our priority is on maintaining utilization and we are targeting operators who we believe have some insulation to current market challenges due to attractive acreage, size and hedging profiles, among other factors. We believe that the strategic investments in vertical integration that we have made, and our efforts to lower our cost base and improve our operational capabilities and efficiencies, will help us manage through this down-cycle. Although we believe we are prepared for the challenges that lie ahead, the weak activity and pricing environment characterizing this downturn will negatively impact our financial and operating results over the near term.

Competition and Demand for Our Services

We operate in highly competitive areas of the energy services industry with significant potential for excess capacity. 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. Utilization and pricing for our services have in the past been negatively affected by increases in supply relative to demand in our operating areas. Additionally, our operations are concentrated in geographic markets that are highly competitive. 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 hydraulic fracturing services include Halliburton, Schlumberger, Baker Hughes, CalFrac Well services, Trican, Weatherford International, RPC, Inc., Pumpco, an affiliate of Superior Energy Services, and Frac Tech. Our major competitors for our coiled tubing and other well stimulation services include Halliburton, Schlumberger, Baker Hughes, RPC, Inc. and a significant number of regional businesses. Our major competitors for our wireline services include Schlumberger, Halliburton and Archer.

Results of Operations

Our results of operations are driven primarily by four interrelated variables: (1) the drilling and stimulation activities of our customers, which directly affects the demand for our services; (2) the prices we are able to charge for our services; (3) the cost of products, materials and labor, and our ability to pass those costs on to our customers; and (4) our service performance.

The majority of our revenue is generated from our hydraulic fracturing services. Historically, most of our hydraulic fracturing services were performed under long-term “take-or-pay” contracts, the last of which expired in February 2014. We now provide substantially all our hydraulic fracturing services, along with our other core services, in the spot market. Accordingly, we are now significantly affected by, among other things, the pricing pressures and other conditions of the markets in which we provide our services. For additional information about the factors impacting our business and results of operations, please see “Industry Trends and Outlook.”

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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 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		1,162,708			738,962			423,746
Selling, general and administrative expenses		199,037			136,910			62,127
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 primarily from our hydraulic fracturing services and $129.7 million 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 $423.7 million, or 57.3%, to $1.2 billion for the year ended December 31, 2014, as compared to $739.0 million for the year ended December 31, 2013. Our Completion Services segment had $350.0 million of additional direct costs primarily from our hydraulic fracturing services and $69.0 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 69.0% for the year ended December 31, 2013 to 72.3% 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 $62.1 million, or 45.4%, to $199.0 million for the year ended December 31, 2014, as compared to $136.9 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

Depreciation and amortization expenses 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 same period in 2013. The increase was primarily related to $25.9 million from our Completion Services segment due to the deployment of new, incremental hydraulic fracturing and coiled tubing equipment and from our wireline services due to the deployment of new, incremental wireline and pressure pumping equipment.

Interest Expense, net

Interest expense increased by $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 same period in 2013 due to increased average debt balances.

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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.

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Results for the Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

The following table summarizes the change in our results of operations for the year ended December 31, 2013 when compared to the year ended December 31, 2012 (in thousands):


	Years Ended December 31,
	2013			2012			$ Change
Revenue	$	1,070,322		$	1,111,501		$	(41,179	)
Costs and expenses:
Direct costs		738,962			686,811			52,151
Selling, general and administrative expenses		136,910			94,556			42,354
Research and development		5,005			—			5,005
Depreciation and amortization		74,703			46,912			27,791
Loss on disposal of assets		527			692			(165	)

Operating income		114,215			282,530			(168,315	)
Other income (expense):
Interest expense, net		(6,550	)		(4,996	)		(1,554	)
Other income (expense), net		53			(105	)		158

Total other expenses, net		(6,497	)		(5,101	)		(1,396	)

Income before income taxes		107,718			277,429			(169,711	)
Income tax expense		41,313			95,079			(53,766	)

Net income	$	66,405		$	182,350		$	(115,945	)

Revenue

Revenue decreased $41.2 million, or 3.7%, for the year ended December 31, 2013, as compared to the year ended December 31, 2012. Our revenue for the year ended December 31, 2013 was negatively impacted by our Completion Services segment, including a $156.9 million decrease in revenue primarily due to lower utilization and pricing for our hydraulic fracturing services, partially offset by $148.7 million in incremental wireline services revenue as a result of the acquisition of our wireline business in June 2012, as well as a $33.0 million decrease in equipment manufacturing revenue included in our Other Services segment due to lower demand as a result of excess equipment capacity in the energy services industry.

Direct Costs

Direct costs increased $52.2 million, or 7.6%, to $739.0 million for the year ended December 31, 2013, as compared to $686.8 million for the year ended December 31, 2012 primarily due to an increase of $86.5 million in incremental Completion Services costs as a result of the acquisition of our wireline business in June 2012, partially offset by a decrease of $27.1 million in equipment manufacturing included in our Other Services segment cost as a result of lower third-party sales. As a percentage of revenue, direct costs increased from 61.8% for the year ended December 31, 2012 to 69.0% for the year ended December 31, 2013 due to increased exposure to a highly competitive spot market in the pressure pumping industry which resulted in significantly lower pricing for our hydraulic fracturing services.

Selling, General and Administrative Expenses (SG&A)

SG&A increased $42.4 million, or 44.8%, to $136.9 million for the year ended December 31, 2013, as compared to $94.6 million for the year ended December 31, 2012. The increase was primarily due to $17.9 million in 2013 incremental costs related to our Completion Services segement as a result of the wireline services business, which we acquired in June 2012. During 2013, we expanded key administrative functions to support the growth of our business; this in turn led to an increase of $14.9 million in payroll and personnel costs. Further, we incurred $12.1 million in incremental costs related to our strategic growth initiatives, including our international expansion efforts, our research and technology efforts and our downhole tools and specialty chemicals businesses.

During the second quarter of 2013, we completed a review of our SG&A expenses and determined that certain costs, such as insurance costs associated with personnel charged to direct labor, are more appropriately reflected in direct costs on our consolidated statements of operations. As such, reclassifications have been made to the year ended December 31, 2012 to conform to our year ended December 31, 2013 presentation. The amount of the reclassification for the year ended December 31, 2012 was $13.8 million.

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Research and Development Expenses (R&D)

During 2013, we made significant investments in enhancing our technological capabilities, including through the further build-out of a research and technology division. In order to more effectively communicate our commitment to technological advancement, we elected to include a new line item of “Research and Development Expense” or “R&D” on our consolidated statements of operations for costs related to our ongoing research and technology initiatives. We incurred $5.0 million in R&D expenses for the year ended December 31, 2013.

Depreciation and Amortization

Depreciation and amortization expenses increased $26.9 million, or 59%, to $74.7 million for the year ended December 31, 2013 as compared to $46.9 million for the same period in 2012. The increase was primarily related to our Completion Services segment with $14.1 million in incremental costs due to the acquisition of our wireline business in June 2012 and $12.8 million in incremental costs due to the addition and deployment of new hydraulic fracturing and coiled tubing equipment.

Interest Expense, net

Interest expense increased by $1.6 million, or 31%, to $6.6 million for the year ended December 31, 2013 as compared to $5.0 million for the same period in 2012. The increase was primarily attributable to higher average outstanding debt balances period over period. This debt was incurred to fund the June 2012 acquisition of our wireline business.

Income Taxes

We recorded income tax expense of $41.3 million for the year ended December 31, 2013, at an effective rate of 38.4%, compared to $95.1 million for the year ended December 31, 2012, at an effective rate of 34.3%. The increase in the effective tax rate is primarily due to lower pre-tax book income, which caused permanent differences between book and taxable income and state income taxes to have a higher proportionate impact on the calculation of the effective tax rate.

Liquidity and Capital Resources

Since the beginning of 2011, our primary sources of liquidity have been cash flows from operations, borrowings under our credit facilities and the net proceeds that we received from our IPO. Our primary uses of capital during this period were for the growth of our Company, including the purchase and maintenance of equipment for our core service lines, strategic acquisitions that complement and enhance our business, geographic expansion and our ongoing strategic initiatives. Our capital expenditures, maintenance costs and other expenses have increased substantially over the last few years in line with our significant growth.

Over the past two years, we have continually invested in our ongoing strategic initiatives, most notably including the build-out of our research and technology division, the expansion of our service offerings, the enhancement of our core services, vertical integration and international expansion. These investments have resulted in increased capital expenditures and costs. 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. However, over the course of 2015 and beyond, we expect to generate meaningful cost savings from a number of these projects. Further, we believe that these investments will yield significant financial returns, as well as significant cost savings to us, over the long term.

Additionally, during 2014 we incurred significant transaction, integration and transition costs associated with the Transactions and we expect to continue to incur significant costs associated with completing the transaction, combining the operations of the C&P Business with our business and achieving desired synergies. Upon closing of the Transactions, we believe that our combined company will have improved financial strength and operational scale, as well as improved liquidity due to a greater combined lending base, coupled with the expected benefit of a lower cost of capital. We expect to enter into a new revolving credit facility (the “New C&J Revolving Credit Facility”) in an aggregate principal amount of $520 million upon the closing of the Transactions, which we believe will enable us to maximize the value of our combined asset base. We believe that this improved liquidity will also allow us to compete more effectively through enhanced access to capital and more readily manage any risk inherent in its business. The New C&J Revolving Credit Facility is expected to contain customary restrictive covenants and financial covenants that may limit the combined company’s ability to engage in activities that may be in its long-term best interests, including minimum interest coverage and maximum total leverage and secured leverage ratios and covenants that may limit the ability of the combined company 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 and prepay certain indebtedness.

In addition to the Transactions, we are actively exploring opportunities to further expand and diversify our product and service offerings, including through acquisitions of technologies, assets and businesses that represent a good operational, strategic, and/or synergistic fit with our existing service offerings. We are also committed to geographic expansion, both domestically and internationally. The successful execution of our long-term growth strategy depends on our ability to raise capital as needed.

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Historically, we have been able to continue to generate solid cash flows in spite of challenging market conditions and our free cash flow and strong balance sheet has allowed us to be flexible with our approach to organic growth and acquisition opportunities. We believe that we are well-positioned to capitalize on available opportunities and finance future growth. However, sustained pressure on pricing and decreased utilization for our services could cause us to reduce our capital expenditures. If this current industry downturn and depressed pricing environment for crude oil persists or worsens, we are prepared to delay further investment 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.

At the end of 2014 we saw a pullback in completion activity in response to commodity price declines and the slowdown has intensified in 2015. We are currently experiencing a decrease in activity across our customer base, which in turn has increased competition and put pressure on pricing for our services. Although the severity and extent of this downturn is uncertain, absent a significant recovery in commodity prices, we expect that activity and pricing levels will continue to decline. In reaction to this challenging environment, we have put a sharp focus on cost management, particularly input costs and labor. In order to offset as much of the pricing concessions as we can, we are working with our vendors to lower input costs. Our priority is on maintaining utilization and market share and we are targeting operators who we believe have some insulation to current market challenges due to attractive acreage, size and hedging profiles, among other factors. We believe that the strategic investments in vertical integration that we have made, and our efforts to lower our cost base and improve our operational capabilities and efficiencies, will help us manage through this down-cycle. Although we believe we are prepared for the challenges that lie ahead, the weak activity and pricing environment characterizing this downturn will negatively impact our financial and operating results over the near term.

As of December 31, 2014, we had $315.0 million outstanding under the Credit Facility and $2.0 million in letters of credit, and as of February 13, 2015, we had $337.5 million outstanding and $7.2 million in letters of credit, leaving $155.3 million available for additional borrowings at that date. Our Credit Facility contains covenants that require us to maintain an interest coverage ratio and a leverage ratio, as well as to satisfy certain other conditions. We are also subject to certain limitations on our ability to make capital expenditures on a fiscal year basis. These covenants are subject to a number of exceptions and qualifications. As of December 31, 2014, and through the date of this report, we are in compliance with these covenants.

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. Our current indebtedness, or, following closing of the Transactions, the substantial indebtedness that will be incurred in connection with the Transactions, could limit our ability to finance future growth and adversely affect our operations and financial condition. Additionally, the financial and other restrictive covenants obligations contained in the agreements governing that indebtedness may restrict our operational flexibility and our ability to obtain additional financing to fund growth, working capital or capital expenditures, or to fulfill debt service requirements or other cash requirements.

We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our ability to fund operating cash flow shortfalls, if any, and to fund planned capital expenditures will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Based on our existing operating performance, we believe our cash flows from operations and existing capital, coupled with borrowings available under our Credit Facility, will be adequate to meet operational and capital expenditure needs over the next twelve months.

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 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, which are made to extend the useful life of partially or fully depreciated assets.

Capital expenditures totaled $315.7 million for the year ended December 31, 2014, which primarily consisted of construction costs for new equipment. Given current market conditions and exclusive of the Transactions, our 2015 capital expenditures are currently expected to range from $110 million to $135 million. Likewise, given the large asset base that we will acquire upon closing of the Transactions, coupled with current market conditions, we currently expect that most of our 2015 capital expenditure plan will be directed to capital expenditures made to extend the useful life of our existing equipment.

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At closing of the Transactions, we believe that our combined company will have improved liquidity due to a greater combined lending base, as well as the expected benefit of a lower cost of capital. It is expected that we will enter into a revolving credit facility (the “New C&J Revolving Credit Facility”) in an aggregate principal amount of $520 million upon the closing of the pending Nabors Transaction, which we believe will enable us to maximize the value of our combined asset base. We believe that this improved liquidity will also allow us to compete more effectively through enhanced access to capital and more readily manage any risk inherent in our business.

We continually monitor new advances in equipment, technologies and processes that will further enhance our existing service capabilities, reduce costs and increase efficiencies. During the year ended December 31, 2013, we significantly enhanced our research and technology capabilities, including through the establishment of a Research & Technology division. We assembled a team of technology-focused engineers and constructed a state-of-the-art technology-focused research and development facility. Over the course of 2014, we further advanced our research and technology capabilities as we continued to focus on developing innovative, fit-for-purpose solutions designed to reduce costs, increase completion efficiencies, enhance our service capabilities and add value for our customers. We believe that these efforts will enable us to more effectively compete against larger integrated energy services companies, both domestically and internationally. Our continued investment in our strategic initiatives has resulted in increasing capital expenditures and additional costs during 2014, and we expect that our costs and expenses will continue to increase as we further develop these projects. However, over the course of 2015, we expect to generate meaningful cost savings from a number of these projects. Further, we believe that these investments will yield significant financial returns, as well as significant cost savings to us, over the long term. Our strategic initiatives have not contributed significant third-party revenue to date, and we do not expect that any will contribute meaningful third-party revenue over the near term. We currently intend to continue to invest in our research and technology capabilities as a key element of our growth strategy. However, if this current industry downturn and depressed pricing environment for crude oil persist or worsen, 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.

Additionally, we are actively evaluating opportunities to further expand our business and grow our geographic footprint, including through strategic acquisitions and targeted expansion, both domestically and internationally. With respect to our international expansion efforts, we are investing in the infrastructure needed to capitalize on available opportunities and support future operations. We have established an office in Dubai, as well as a facility in Saudi Arabia to service our first international contract. During the first quarter of 2015, we expect to commence construction of an operational facility in Dubai to support our anticipated future Middle East operations. As we pursue compelling opportunities, we will continue to make capital investment decisions that we believe will support our long-term growth strategy. However, we will continue to monitor the economic environment and demand for our services and adjust our business strategy as necessary.

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,
	2014			2013			2012

Cash flow provided by (used in):
Operating activities	$	181,837		$	181,101		$	253,930
Investing activities		(343,412	)		(165,295	)		(457,393	)
Financing activities		157,178			(15,834	)		171,125

Decrease in cash and cash equivalents	$	(4,397	)	$	(28	)	$	(32,338	)

Cash Provided by Operating Activities

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 noncash 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 flow activities.

Net cash provided by operating activities was $72.8 million lower for the year ended December 31, 2013 as compared to the same period in 2012. The primary items contributing to the decrease in cash provided by operating activities were lower net income, offset by higher depreciation and amortization and a decrease in the year over year growth of accounts receivable. Our lower net income was primarily a result of increased spot market exposure with our hydraulic fracturing business as well as increased costs associated with our ongoing strategic initiatives. Depreciation and amortization costs were higher due to continued capital purchases throughout the year across all service lines. The decline in our year over year growth of accounts receivable is primarily due to decreased activity levels within our hydraulic fracturing business.

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Cash Flows Used in Investing Activities

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 Completion Services segment, inclusive of $33.2 million related to the Tiger Acquisition.

Net cash used in investing activities increased $292.1 million for the year ended December 31, 2013 as compared to the same period in 2012. This increase was due primarily to the $273.4 million of cash paid to acquire our wireline business in 2012 as compared to the combined cash paid of $14.6 million for our two strategic acquisitions during 2013, and to a lesser extent a decrease in capital expenditures.

Cash Flows Provided by (Used in) Financing Activities

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 Transactions.

Net cash used in financing activities was $15.8 million for the year ended December 31, 2013 as compared to net cash provided by financing activities of $171.1 million for the same period in 2012. Cash used in financing activities for the year ended December 31, 2013 primarily consisted of approximately $20.3 million net repayments on the Credit Facility, partially offset by proceeds from the exercise of stock options previously granted under our equity plans. Financing activities for 2012 consisted primarily of $220.0 million in borrowings under our Credit Facility to fund a portion of the acquisition cost of our wireline business, partially offset by $50.0 million of repayments later in the year.

Contractual Obligations

The following table summarizes our contractual cash obligations as of December 31, 2014 (in thousands):


Contractual Obligation	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years

Credit Facility⁽¹⁾	$	328,388	$	10,322	$	318,066	$	—	$	—
Capital leases⁽²⁾		44,935		4,875		7,318		7,471		25,271
Operating leases		25,987		7,760		8,626		4,127		5,474
Inventory & materials		72,012		66,412		2,800		2,800		—
Service Equipment and other capital expenditures		15,860		15,860		—		—		—

Total	$	487,182	$	105,229	$	336,810	$	14,398	$	30,745

(1)	Includes estimated interest costs at an interest rate of 3.0% along with related charges.

(2)	Capital lease amounts include $6.2 million in interest payments.

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, 2014.

Description of Our Indebtedness as of December 31, 2014

Credit Facility. On April 19, 2011, we entered into a five-year $200.0 million senior secured revolving credit agreement with Bank of America, N.A., as administrative agent, swing line lender and letter of credit issuer, Comerica Bank, as letter of credit issuer and syndication agent, Wells Fargo Bank, National Association, as documentation agent, and various other lenders. Obligations under the Credit Facility are guaranteed by our wholly-owned domestic subsidiaries (the “Guarantor Subsidiaries”), other than immaterial subsidiaries. Effective June 5, 2012, we entered into Amendment No. 1 and Joinder to Credit Agreement (the “Amendment”) primarily to facilitate and permit us to fund a portion of the acquisition of our wireline business.

The Amendment increased our borrowing capacity under the Credit Facility to $400.0 million. To effectuate this increase, new financial institutions were added to the Credit Facility as lenders and certain existing lenders severally agreed to increase their respective commitments. Pursuant to the Amendment, the aggregate amount by which we may periodically increase commitments through incremental facilities was increased from $75.0 million to $100.0 million, the sublimit for letters of credit was left unchanged at $200.0 million and the sublimit for swing line loans was increased from $15.0 million to $25.0 million. On June 7, 2012, we drew $220.0 million from the Credit Facility to fund a portion of the purchase price of the acquisition of our wireline business.

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In November 2014, we exercised in full the accordion feature of our revolving credit facility, increasing the total lender commitment under the facility by $100.0 million to a total of $500.0 million. As of December 31, 2014, we had $315.0 million outstanding under the Credit Facility and $2.0 million in letters of credit, and as of February 13, 2015, we had $337.5 million outstanding and $7.2 million in letters of credit, leaving $155.3 million available for borrowing.

Loans under our Credit Facility are denominated in U.S. dollars and will mature on April 19, 2016. Outstanding loans bear interest at either LIBOR or a base rate, at our election, plus an applicable margin which ranges from 1.25% to 2.00% for base rate loans and from 2.25% to 3.00% for LIBOR loans, based upon our Consolidated Leverage Ratio. The Consolidated Leverage Ratio is the ratio of funded indebtedness to EBITDA for us and our subsidiaries on a consolidated basis. All obligations under our Credit Facility are secured, subject to agreed-upon exceptions, by a first priority perfected security interest in all real and personal property of us and the Guarantor Subsidiaries. The weighted average interest rate as of December 31, 2014 was 3.0%.

The Credit Facility contains customary affirmative covenants including financial reporting, governance and notification requirements. The Amendment made certain changes to the Credit Facility’s affirmative covenants, including the financial reporting and notification requirements, and the Credit Facility’s negative covenants, including the restriction on our ability to conduct asset sales, incur additional indebtedness, issue dividends, grant liens, issue guarantees, make investments, loans or advances and enter into certain transactions with affiliates. Additionally, the Amendment altered the restriction on capital expenditures to allow us to make an unlimited amount of capital expenditures so long as (i) the pro forma Consolidated Leverage Ratio is less than 2.00 to 1.00, (ii) we have pro forma liquidity of greater than $40.0 million, (iii) no default exists and (iv) the capital expenditures could not reasonably be expected to cause a default. Further, in the event that these conditions are not met, we will be permitted to make capital expenditures in any fiscal year in an amount equal to the greater of (x) 12.5% of the consolidated tangible assets of us and our subsidiaries and (y) $200.0 million, provided that up to $50.0 million of such amount in any fiscal year may be rolled over to the subsequent fiscal year and up to $50.0 million may be pulled forward from the subsequent fiscal year. These capital expenditure restrictions do not apply to capital expenditures financed solely with the proceeds from the issuance of qualified equity interests and asset sales or normal replacement and capital expenditures made to extend the useful life of our existing equipment.

The Credit Facility requires us to maintain, measured on a consolidated basis, (1) an Interest Coverage Ratio of not less than 3.00 to 1.00 and (2) a Consolidated Leverage Ratio of not greater than 3.25 to 1.00. As of December 31, 2014, and through the date of this report, we are in compliance with all debt covenants.

Capitalized terms used in “Description of Our Indebtedness” but not defined herein are defined in the Credit Facility.

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 is 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.

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Impairment of Long-Lived Assets. We assess the impairment of our long-lived assets, which include property, plant and equipment, and intangible assets with finite lives, whenever events or changes in circumstances (“triggering events”) indicate that the carrying value may not be recoverable. Such indicators include changes in our business plans, a change in the physical condition of a long-lived asset or the extent or manner in which it is being used, or a severe or sustained downturn in the oil and natural gas industry.

Recoverability is assessed by using 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. If the undiscounted future net cash flows are less than the carrying amount of the asset, the asset is deemed impaired. The amount of the impairment is measured as the difference between the carrying value and the fair value of the asset.

We make estimates and judgments about future undiscounted cash flows and fair values. Although our cash flow forecasts are based on assumptions that are consistent with our plans, there is a significant degree of judgment involved in determining the cash flows attributable to a long-lived asset over its estimated remaining useful life. Our estimates of anticipated cash flows could be reduced significantly in the future and as a result, the carrying amounts of our long-lived assets could be subject to impairment charges in the future.

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 hydraulic fracturing, coiled tubing, wireline, pumpdown, directional drilling and international coiled tubing service lines.

It was concluded that the sharp fall in commodity prices during the second half of 2014 constituted a triggering event due to the potential for a slowdown in activity across the Company’s customer base, which in turn would increase competition and put pressure on pricing for its services. Although the severity and extent of this downturn is uncertain, absent a significant recovery in commodity prices, activity and pricing levels may decline in future periods. As a result of the triggering event during the fourth quarter of 2014, a recoverability test was performed on the long-lived asset groups supporting each of the Company’s service lines. As of December 31, 2014, the recoverability testing for each asset group yielded an estimated undiscounted net cash flow that was greater than the carrying amount of the related assets, and as such, no impairment loss was recognized during the fourth quarter of 2014. The test results for the hydraulic fracturing service line highlighted a smaller cushion of less than 15%. If recoverability testing is performed in future periods and this service line experiences a decline in undiscounted cash flows, the service line could be susceptible to an impairment loss.

Goodwill, Intangible Assets and Amortization. Goodwill is allocated to the Company’s three reporting units: Stimulation and Well Intervention Services, Wireline Services and Equipment Manufacturing. 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 above, indicate the carrying value of goodwill may not be recoverable and that a potential impairment exists.

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 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 includes hypothetically valuing the tangible and intangible assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Then, the implied fair value of the reporting unit’s goodwill is compared to the carrying value of that goodwill. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess, not to exceed the carrying value.

The Company’s detailed 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.

Judgment is used in assessing whether goodwill should be tested more frequently for impairment than annually. Factors such as unexpected adverse economic conditions, competition, market changes and other external events may require more frequent assessments.

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It was concluded that the aforementioned sharp fall in commodity prices during the second half of 2014 triggered the need to test goodwill for impairment as of December 31, 2014. The Company chose to bypass a qualitative approach and opt instead to employ detailed impairment testing methodologies.

Income approach

The income approach was based on a discounted cash flow model, which utilizes present values of cash flows to estimate fair value. For the Stimulation and Well Intervention Services and Wireline Services reporting units, the future cash flows were projected based on estimates of projected revenue growth, fleet count, utilization, gross profit rates, SG&A rates, working capital fluctuations, and capital expenditures. For the Equipment Manufacturing reporting unit, the future cash flows were projected based 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 take into account known market conditions as of December 31, 2014, and management’s anticipated business outlook, both of which have been impacted by the 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 15.0% for both Stimulation and Well Intervention Services and Wireline Services and 15.5% for Equipment Manufacturing reporting units. These assumptions were derived from unobservable inputs and reflect management’s judgments and assumptions.

Market approach

The market approach was based upon two methods: the guideline public company method and the guideline transaction 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 averaged 3.9x for Stimulation and Well Intervention Services, 3.9x for Wireline Services, and 4.9x for Equipment Manufacturing.

The application of the guideline transaction method was based upon recent sales or purchases of companies operating within the same industry as the Company. Based on this set of transaction data, price-to-earnings multiples were derived and a range of price-to-earnings multiples was determined for each reporting unit. The selected market multiples were 5.0x for Stimulation and Well Intervention Services, 4.4x for Wireline Services, and 4.9x for Equipment Manufacturing.

The fair value determined under both market approaches is sensitive to these market multiples, and a decline in any of the multiples could reduce the estimated fair value of any of the three reporting units below their respective carrying values. Earnings estimates were derived from unobservable inputs that require significant estimates, judgments and assumptions as described in the income approach.

The estimated fair value determined under the income approach was consistent with the estimated fair value determined under both market approaches. For purposes of the goodwill impairment test, the concluded fair value for each of the three reporting units consisted of an average under the income approach and the two market approaches.

Based on the detailed impairment testing performed as of December 31, 2014, (i) the Stimulation and Well Intervention Services reporting unit estimated fair value exceeded its carrying value by approximately 14%, and it was concluded that the goodwill balance of $69.1 million was not impaired; (ii) the Wireline Services reporting unit estimated fair value exceeded its carrying value by approximately 12%, and it was concluded that the goodwill balance of $146.1 million was not impaired; and (iii) the Equipment Manufacturing reporting unit estimated fair value exceeded its carrying value by approximately 48%, and it was concluded that the goodwill balance of $4.7 million was not impaired. 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 any of the three reporting unit cash flow projections or changes in other key assumptions may result in a goodwill impairment charge in the future.

Indefinite-lived intangible assets

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As noted above, the sharp fall in commodity prices during the second half of 2014 was deemed a triggering event and detailed impairment testing was performed 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 exceeded its carrying value by approximately 55% and it was determined that the trade name carry value of $6.2 million was not impaired as of December 31, 2014.

The Company’s intangible assets associated with intellectual property, research and development (“IPR&D”) were evaluated using a qualitative approach since the technology is still in the testing phase and management continues to actively pursue development and planned marketing of the new technology. Based on this evaluation which includes successful test results within the Company’s research and development facilities, it was determined that the IPR&D carry value of $7.6 million was not impaired as of December 31, 2014.

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 analyses. 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 3 – Acquisitions” in Item 8 “Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the acquisition-related information associated with acquisitions completed in the last three fiscal years.

Revenue Recognition¹. 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 collectability is reasonably assured, as follows:

Hydraulic Fracturing Revenue. We provide hydraulic fracturing services pursuant to contractual arrangements, such as term contracts and pricing agreements, or on a spot market basis. Under either scenario, revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or more fracturing stages. Once a job has been completed 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, 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 we may enter into from time to time, such as those associated with an award from a bid process, customers typically commit to targeted utilization levels based on a specified number of hours of service at agreed-upon pricing, but without termination penalties or obligations to pay for services not used by the customer. In addition, the agreed-upon pricing is typically subject to periodic review, as specifically defined in the agreement, and may be adjusted upon the agreement of both parties.

Historically, most of our hydraulic fracturing services were performed under our long-term “take-or-pay” contracts, the last of which expired in February 2014. These legacy term contracts had minimum utilization requirements and favorable pricing terms relative to the spot market pricing experienced during 2014. Under our legacy term contacts, our customers were typically obligated to pay us on a monthly basis for a specified number of hours of service, whether or not those services were actually used. To the extent customers use more than the specified contract minimums, we were paid a pre-agreed amount for the provision of such additional services. Additionally, these term contracts restricted the ability of the customer to terminate the contract in advance of its expiration date.

¹	NTD: C&J to advise as to whether any revisions should be made to this section. Seems to be based off of old segment disclosure.

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Coiled Tubing and Other Well Stimulation Revenue. We provide coiled tubing and other well stimulation services, including nitrogen, pressure pumping and thru-tubing services, as well as directional drilling 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 these services and resources on an hourly basis at agreed-upon spot market rates.

Revenue from Materials Consumed While Performing Services. We generate revenue from fluids, proppants and other materials that are consumed while performing hydraulic fracturing services. 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 well stimulation services revenue, the Company generates revenue from stimulation fluids, nitrogen, coiled tubing materials and other consumables used during those processes.

Wireline Revenue. We provide cased-hole wireline, pumpdown and other complementary services, including logging, perforating, pipe recovery and pressure testing 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. Revenue is recognized when the services and equipment are provided and the job is completed. The Company typically charges the customer on a per job basis for these services at agreed-upon spot market rates.

Equipment Manufacturing Revenue. We enter into arrangements to construct new equipment, refurbish and repair equipment and provide oilfield parts and supplies to third-party customers in the energy services industry, as well as to our Completion Services segment. Revenue is recognized and the customer is invoiced upon the completion and delivery of each order to the customer.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at the amount billed to customers and are ordinarily due upon receipt. We provide an allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Provisions for doubtful accounts are recorded when it is deemed probable that the customer will not make the required payments at either contractual due dates or in the future. The allowance for doubtful accounts totaled $2.2 million at December 31, 2014 and $1.7 million at December 31, 2013. Bad debt expense was $0.6 million, $0.7 million and $0.6 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Stock-Based Compensation. Our stock-based compensation consists of restricted stock and nonqualified stock options. We recognize stock-based compensation expense on a straight-line basis over the requisite service period of the award. We value restricted stock grants based on the closing price of our common stock 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 stock-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 stock-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

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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 August 2014, the Financial Accounting Standards Board (“FASB”) issued guidance on disclosures of uncertainties about an entity’s ability to continue as a going concern. The guidance requires our evaluation of whether there are conditions or events that raise substantial doubt about our ability to continue as a going concern within one year after the date that the financial statements are issued. This assessment must be made in connection with preparing financial statements for each annual and interim reporting period. Our evaluation should be based on the relevant conditions and events that are known and reasonably knowable at the date the financial statements are issued. If conditions or events raise substantial doubt about our ability to continue as a going concern, but this doubt is alleviated by our plans, we should disclose information that enables the reader to understand what the conditions or events are, our evaluation of those conditions or events and our plans that alleviate that substantial doubt. If conditions or events raise substantial doubt and the substantial doubt is not alleviated, we must disclose this in the footnotes. We must also disclose information that enables the reader to understand those conditions or events, our evaluation of those conditions or events, and our plans to alleviate the substantial doubt. The guidance is effective for annual periods and interim periods within those annual periods beginning after December 15, 2016. We do not expect the adoption of this new guidance to have a material impact on our financial statements or financial statement disclosures.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires us to recognize the amount of revenue to which we expect to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. We are evaluating the effect ASU 2014-09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method nor has the effect of the standard on our ongoing financial reporting been determined.

In April 2014, the FASB issued new guidance intended to change the criteria for reporting discontinued operations while enhancing disclosures for discontinued operations, which changes the criteria and requires additional disclosures for reporting discontinued operations. The guidance is effective for all disposals of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within annual periods beginning on or after December 15, 2015. We do not expect the adoption of this new guidance to have a material impact on our financial statements or financial statement disclosures.

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, 2014, 2013 and 2012. 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.

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The information provided in this Exhibit is presented only in connection with the reporting changes described in the accompanying Form 8-K/A. Unless expressly stated herein, this information does not reflect events occurring after February 20, 2015, the date we filed the 2014 Form 10-K of C&J Energy Services, Inc. (the “2014 Form 10-K”), and does not modify or update the disclosures therein in any way, other than as required to reflect the change in reportable segments as described in the accompanying Form 8-K/A and set forth in Exhibit 99.1 attached thereto. You should therefore read this information in conjunction with the 2014 Form 10-K and in conjunction with our March 31, 2015 Form 10-Q filed with the Securities and Exchange Commission on May 11, 2015.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

C&J Energy Services Inc.:

We have audited the accompanying consolidated balance sheet of C&J Energy Services Inc. and subsidiaries as of December 31, 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2014. 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 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 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 financial position of C&J Energy Services Inc. subsidiaries as of December 31, 2014 and the results of their operations and their cash flows for the year ended December 31, 2014, 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 Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 20, 2015 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 Inc acquired Tiger Cased Hole Services, Inc. (Tiger) during 2014 and management excluded from its assessment of the effectiveness of C&J Energy Services Inc.’s internal control over financial reporting as of December 31, 2014, Tiger’s internal control over financial reporting associated with 1% of consolidated revenues and 3% of consolidated total assets of C&J Energy Services, Inc. as of and for the year ended December 31, 2014. Our audit of internal controls over financial reporting of C&J Energy Service, Inc. also excluded an evaluation of the internal control over financial reporting of Tiger.

/s/ KPMG LLP

Houston, Texas

February 20, 2015, except as to Notes 11 and 13, which are as of July 15, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

C&J Energy Services, Inc.

We have audited the accompanying consolidated balance sheet of C&J Energy Services, Inc. (a Delaware corporation) and subsidiaries (collectively, the “Company”) as of December 31, 2013, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the two years in the period 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 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 audits 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 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, Inc. and subsidiaries as of December 31, 2013, and the results of their operations and their cash flows for each of the two years in the period 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

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share data)


	As of December 31,
	2014		2013

ASSETS

Current assets:
Cash and cash equivalents	$	10,017	$	14,414
Accounts receivable, net		290,767		152,696
Inventories, net		122,172		70,946
Prepaid and other current assets		29,525		17,066
Deferred tax assets		8,106		1,722

Total current assets		460,587		256,844

Property, plant and equipment, net		783,302		535,574

Other assets:
Goodwill		219,953		205,798
Intangible assets, net		129,468		123,038
Deposits on equipment under construction		7,117		4,331
Deferred financing costs, net		3,786		2,688
Other noncurrent assets		8,533		4,027

Total assets	$	1,612,746	$	1,132,300


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	229,191	$	88,576
Accrued payroll and related costs		16,047		13,711
Accrued expenses		30,794		18,619
Income taxes payable		—		266
Current capital lease obligations		3,873		2,860
Other current liabilities		4,926		1,101

Total current liabilities		284,831		125,133

Deferred tax liabilities		193,340		145,215

Long-term debt and capital lease obligations		349,875		164,205

Other long-term liabilities		2,803		1,596


Total liabilities		830,849		436,149

Commitments and contingencies

Stockholders’ equity

Common stock, par value of $0.01, 100,000,000 shares authorized, 55,333,392 issued and outstanding at December 31, 2014 and 54,604,124 issued and outstanding at December 31, 2013		553		546
Additional paid-in capital		271,104		254,188
Retained earnings		510,240		441,417

Total stockholders’ equity		781,897		696,151

Total liabilities and stockholders’ equity	$	1,612,746	$	1,132,300

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands, except per share data)


	Years Ended December 31,
	2014			2013			2012

Revenue	$	1,607,944		$	1,070,322		$	1,111,501

Costs and expenses:
Direct costs		1,162,708			738,962			686,811
Selling, general and administrative expenses		199,037			136,910			94,556
Research and development		14,327			5,005			—
Depreciation and amortization		108,145			74,703			46,912
(Gain) loss on disposal of assets		(17	)		527			692


Operating income		123,744			114,215			282,530

Other income (expense):
Interest expense, net		(9,840	)		(6,550	)		(4,996	)
Other income (expense), net		598			53			(105	)

Total other income (expense)		(9,242	)		(6,497	)		(5,101	)


Income before income taxes		114,502			107,718			277,429

Income tax expense		45,679			41,313			95,079


Net income	$	68,823		$	66,405		$	182,350


Net income per common share:
Basic	$	1.28		$	1.25		$	3.51

Diluted	$	1.22		$	1.20		$	3.37


Weighted average common shares outstanding:
Basic		53,838			53,038			52,008

Diluted		56,513			55,367			54,039

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(Amounts in thousands)


	Common Stock						Additional Paid-in Capital			Retained Earnings		Total
	Number of Shares			Amount, at $0.01 par value			Additional Paid-in Capital			Retained Earnings		Total

Balance, December 31, 2011		51,887		$	519		$	201,874		$	192,662	$	395,055

Issuance of restricted stock, net of forfeitures		780			7			(7	)		—		—

Exercise of stock options		465			5			2,568			—		2,573

Tax effect of stock-based compensation		—			—			1,901			—		1,901

Stock-based compensation		—			—			18,012			—		18,012

Net income		—			—			—			182,350		182,350


Balance, December 31, 2012		53,132			531			224,348			375,012		599,891

Issuance of restricted stock, net of forfeitures		669			7			(7	)		—		—

Employee tax withholding on restricted stock vesting		(74	)		(1	)		(1,374	)		—		(1,375	)

Exercise of stock options		877			9			5,210			—		5,219

Tax effect of stock-based compensation		—			—			3,430			—		3,430

Stock-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 stock, net of forfeitures		723			7			(7	)		—		—

Employee tax withholding on restricted stock vesting		(153	)		(2	)		(4,376	)		—		(4,378	)

Exercise of stock options		159			2			831			—		833

Tax effect of stock-based compensation		—			—			2,118			—		2,118

Stock-based compensation		—			—			18,350			—		18,350

Net income		—			—			—			68,823		68,823


Balance, December 31, 2014		55,333		$	553		$	271,104		$	510,240	$	781,897

See accompanying notes to consolidated financial statements

- 8 -

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)


	Years Ended December 31,
	2014			2013			2012

Cash flows from operating activities:
Net income	$	68,823		$	66,405		$	182,350
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		108,145			74,703			46,912
Deferred income taxes		33,185			16,513			15,926
Provision for doubtful accounts, net of write-offs		600			689			600
Equity (earnings) loss from unconsolidated affiliate		(471	)		160			—
(Gain) Loss on disposal of assets		(17	)		527			692
Stock-based compensation expense		18,350			22,581			18,012
Amortization of deferred financing costs		1,168			1,160			923
Inventory write-down		—			870			—
Changes in operating assets and liabilities:
Accounts receivable		(135,784	)		14,704			(10,621	)
Inventories		(50,001	)		(10,495	)		(11,263	)
Prepaid expenses and other current assets		(12,154	)		(12,405	)		7,107
Accounts payable		132,420			11,991			(1,195	)
Payroll and related costs and accrued expenses		14,157			2,710			5,373
Income taxes payable		(301	)		(3,888	)		1,765
Other		3,717			(5,124	)		(2,651	)

Net cash provided by operating activities		181,837			181,101			253,930


Cash flows from investing activities:
Purchases of and deposits on property, plant and equipment		(307,598	)		(151,810	)		(181,426	)
Proceeds from disposal of property, plant and equipment		719			1,151			434
Payments made for business acquisitions, net of cash acquired		(33,533	)		(14,636	)		(273,401	)
Investment in unconsolidated subsidiary		(3,000	)		—			(3,000	)

Net cash used in investing activities		(343,412	)		(165,295	)		(457,393	)


Cash flows from financing activities:
Proceeds from revolving debt		229,000			60,000			245,000
Payments on revolving debt		(64,000	)		(80,306	)		(75,000	)
Payments of long-term debt		—			(638	)		—
Payments of capital lease obligations		(4,165	)		(2,184	)		(1,121	)
Financing costs		(2,265	)		—			(2,243	)
Proceeds from stock options exercised		833			5,219			2,573
Employee tax withholding on restricted stock vesting		(4,378	)		(1,375	)		—
Excess tax benefit from stock-based award activity		2,153			3,450			1,916

Net cash provided by (used in) financing activities		157,178			(15,834	)		171,125


Net decrease in cash and cash equivalents		(4,397	)		(28	)		(32,338	)
Cash and cash equivalents, beginning of year		14,414			14,442			46,780

Cash and cash equivalents, end of year	$	10,017		$	14,414		$	14,442


Supplemental cash flow disclosures:
Cash paid for interest	$	8,525		$	5,473		$	3,975

Cash paid for income taxes	$	16,125		$	38,819		$	75,619


Non-cash investing and financing activity:
Capital lease obligations	$	25,847		$	13,487		$	—

Change in accrued capital expenditures	$	8,120		$	6,177		$	753

Non-cash consideration for business acquisition	$	—		$	2,556		$	—

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

C&J Energy Services, Inc. is a publicly traded corporation listed on the New York Stock Exchange under the symbol “CJES.” The Company was founded in Texas in 1997 as a partnership, and reorganized as a Texas corporation in 2006. In December 2010, the Company converted to a Delaware corporation in connection with its initial public offering, which was completed in August 2011. C&J Energy Services, Inc. is a holding company and substantially all of its operations are conducted through, and substantially all of its assets are held by its primary operating subsidiary, C&J Spec-Rent Services, Inc. Through its subsidiaries, the Company operates in three reportable segments: Completion Services, Well Support Services and Other Services. The Company provides a full range of well services involved in the completion, life-of-well maintenance and plugging and abandonment of a well to oil and natural gas drilling and production companies primarily in North America. The Company’s services include hydraulic fracturing, coiled-tubing, cased-hole wireline, cementing, workover, well-servicing, and other ancillary well site services. Additionally, the Company provides fluid logistics services, including those related to the transportation, storage and disposal of fluids that are used in the drilling, development and production of hydrocarbons. The Company operates in most of the major oil and natural 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. See “Note 11 – Segment Information” for further discussion regarding the Company’s reportable segments. As used herein, references to the “Company” or “C&J” are to C&J Energy Services, Inc. together with its consolidated subsidiaries, including C&J International B.V. and C&J International Middle East FZCO.

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 the accounts of C&J and its consolidated subsidiaries. All significant inter-company transactions and account balances have been eliminated upon consolidation.

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, recoverability of long-lived assets and intangibles, goodwill, useful lives used in depreciation and amortization, inventory reserves, income taxes and stock-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, 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, 2014 and 2013, the allowance for doubtful accounts totaled $2.2 million and $1.7 million, respectively. Bad debt expense of $0.6 million, $0.7 million and $0.6 million was included in selling, general, and administrative expenses on the consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012, respectively.

Inventories. Inventories for the Completion Services segment consist of finished goods and raw materials, including equipment components, chemicals, proppants, supplies and materials for the segments’ operations. In addition, the Company’s Completion Services segment includes work-in-process related to manufacturing of downhole tools and data acquisition and control systems. Inventories for the Other Services segment consist of raw materials and work-in-process, including equipment components, supplies and materials. See “Note 11 – Segment Information” for further discussion regarding the Company’s reportable segments.

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. Inventories consisted of the following (in thousands):


	As of December 31,
	2014		2013

Raw materials	$	51,374	$	31,445
Work-in-process		24,408		3,652
Finished goods		47,717		36,690

- 10 -


	As of December 31,
	2014			2013
Total inventory		123,499			71,787
Inventory reserve		(1,327	)		(841	)

Inventory, net of reserve	$	122,172		$	70,946

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 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 $97.2 million, $64.6 million and $39.4 million for the years ended December 31, 2014, 2013 and 2012, 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	2014			2013

Land	Indefinite	$	2,453		$	2,225
Building and leasehold improvements	5-25 years		107,270			50,163
Office furniture, fixtures and equipment	3-5 years		19,716			10,878
Machinery and equipment	3-10 years		767,415			529,854
Transportation equipment	5 years		66,456			46,425

			963,310			639,545
Less: accumulated depreciation			(245,683	)		(148,954	)

			717,627			490,591
Construction in progress			65,675			44,983

Property, plant and equipment, net		$	783,302		$	535,574

Impairment of Long-Lived Assets. Long-lived assets, which include property, plant and equipment, and intangible assets with finite lives, are evaluated on a quarterly basis to identify events or changes in circumstances (“triggering events”) that indicate the carrying value of certain long-lived assets may not be recoverable. Long-lived assets 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 a long-lived asset 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 hydraulic fracturing, coiled tubing, wireline, pumpdown, directional drilling and international coiled tubing service lines. If the estimated undiscounted future net cash flows are less than the carrying amount of the related assets, an impairment loss is determined by comparing the fair value with the carrying value of the related assets.

Goodwill, Intangible Assets and Amortization. Goodwill is allocated to the Company’s three reporting units: Stimulation and Well Intervention Services, Wireline Services and Equipment Manufacturing. 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 above, indicate the carrying value of goodwill may not be recoverable and that a potential impairment exists.

- 11 -

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. The Company may also choose to bypass a qualitative approach and opt instead to employ detailed testing methodologies, regardless of a possible more likely than not outcome. Detailed impairment testing involves comparing the fair value of each reporting unit to its carrying value, including goodwill. Fair value reflects the price a market participant would be willing to pay in a potential sale of the reporting unit. If the fair value exceeds carrying value, then it is concluded that no goodwill impairment has occurred. 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 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.

Income approach

The income approach was based on a discounted cash flow model, which utilizes present values of cash flows to estimate fair value. For the Stimulation and Well Intervention Services and Wireline Services reporting units, the future cash flows were projected based on estimates of projected revenue growth, fleet count, utilization, gross profit rates, selling, general and administrative (“SG&A”) rates, working capital fluctuations, and capital expenditures. For the Equipment Manufacturing reporting unit, the future cash flows were projected based 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 take into account known market conditions as of December 31, 2014, and management’s anticipated business outlook, both of which have been impacted by the decline in commodity prices.

Market approach

- 12 -

Based on the detailed impairment testing performed as of December 31, 2014, (i) the Stimulation and Well Intervention Services reporting unit estimated fair value exceeded its carrying value by approximately 14%, and it was concluded that the goodwill balance of $69.1 million was not impaired; (ii) the Wireline Services reporting unit estimated fair value exceeded its carrying value by approximately 12%, and it was concluded the goodwill balance of $146.1 million was not impaired; and (iii) the Equipment Manufacturing reporting unit estimated fair value exceeded its carrying value by approximately 48%, and it was concluded that the goodwill balance of $4.7 million was not impaired. 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 any of the three reporting unit cash flow projections or changes in other key assumptions may result in a goodwill impairment charge in the future.

Indefinite-lived intangible assets

The Company has approximately $13.8 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. Before employing detailed impairment testing methodologies, the Company may first evaluate the likelihood of impairment by considering qualitative factors. A detailed impairment test for indefinite lived intangible assets encompasses calculating the fair value of an indefinite lived intangible asset and comparing the fair value to its carrying value.

The sharp fall in commodity prices that occurred during the second half of 2014 was deemed a triggering event and detailed impairment testing was performed 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 exceeded its carrying value by approximately 55% and it was determined that the trade name carry value of $6.2 million was not impaired as of December 31, 2014.

- 13 -

Intangible assets consisted of the following (in thousands):


	Amortization Period	As of December 31,
	Amortization Period	2014			2013

Trade name	10-15 years	$	29,315		$	27,665
Customer relationships	8-15 years		116,073			100,593
Non-compete	4-5 years		1,810			1,600
Developed technology	10 years		2,110			2,110
IPR&D	Indefinite		7,598			7,598
Trade name - Total Equipment	Indefinite		6,247			6,247

			163,153			145,813
Less: accumulated amortization			(33,685	)		(22,775	)

Intangible assets, net		$	129,468		$	123,038

Amortization expense for the years ended December 31, 2014, 2013 and 2012 totaled $10.9 million, $10.1 million and $7.5 million, respectively.

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


Years Ending December 31,

2015	$	10,774
2016		10,507
2017		10,374
2018		10,374
2019		10,350
Thereafter		63,244

	$	115,623

Deferred Financing Costs. Costs incurred to obtain financing are capitalized and amortized on a straight-line basis over the term of the loan, which approximates the effective interest method. These costs are classified within interest expense on the consolidated statements of operations and were $1.2 million, $1.2 million and $0.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. Accumulated amortization of deferred financing costs was $3.7 million and $2.5 million at December 31, 2014 and 2013, respectively. Estimated future amortization expense relating to deferred financing costs is as follows (in thousands):


Years Ending December 31,

2015	$	1,160
2016		368

	$	1,528

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 collectability is reasonably assured, as follows:

Hydraulic Fracturing Revenue. The Company provides hydraulic fracturing services pursuant to contractual arrangements, such as term contracts and pricing agreements, or on a spot market basis. Under either scenario, revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or more fracturing stages. Once a job has been completed 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, 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.

- 14 -

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.

Historically, most of the Company’s hydraulic fracturing services were performed under long-term “take-or-pay” contracts, the last of which expired in February 2014. Under these legacy term contracts, customers were typically obligated to pay on a monthly basis for a specified number of hours of service, whether or not those services were actually used. To the extent customers used more than the specified contracted minimums, the Company would be paid a pre-agreed amount for the provision of such additional services.

Coiled Tubing and Other Well Stimulation Revenue. The Company provides coiled tubing and other well stimulation services, including nitrogen, pressure pumping and thru-tubing 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 these services and resources on an hourly basis at agreed-upon spot market rates.

Revenue from Materials Consumed While Performing Services. The Company generates revenue from fluids, proppants and other materials that are consumed while performing hydraulic fracturing services. 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 well stimulation services revenue, the Company generates revenue from various fluids and supplies that are necessarily consumed during those processes.

Wireline Revenue. The Company provides cased-hole wireline, pumpdown and other complementary services, including logging, perforating, pipe recovery and pressure testing 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. Revenue is recognized when the services and equipment are provided and the job is completed. The Company typically charges the customer on a per job basis for these services at agreed-upon spot market rates.

Equipment Manufacturing Revenue. The Company enters into arrangements to construct new equipment, refurbish and repair equipment and provide oilfield parts and supplies to third-party customers in the energy services industry. Revenue is recognized and the customer is invoiced upon the completion and delivery of each order to the customer.

Stock-Based Compensation. The Company’s stock-based compensation plans provide the ability to grant equity awards to the Company’s employees, consultants and non-employee directors. As of December 31, 2014, only nonqualified stock options and restricted stock 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 stock on the grant date. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. Further information regarding the Company’s stock-based compensation arrangements and the related accounting treatment can be found in “Note 6 – Stock-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, and accounts payable approximate their fair values based on their short-term nature. The carrying value of long-term debt and capital lease obligations approximate their fair value, as the interest rates approximate market rates.

Equity Method Investments. The Company has an investment in a joint venture which is 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.

- 15 -

The carrying value of this equity method investment at December 31, 2014 and December 31, 2013 was $7.0 million and $2.8 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 affiliate was approximately $0.5 million and $(0.2 million) for the years ended December 31, 2014 and December 31, 2013, respectively, and is included in other expense, net, on the consolidated statements of operations.

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, 2014, 2013 and 2012, respectively. The Company had no uncertain tax positions as of December 31, 2014.

Earnings Per Share. Basic earnings per share is based on the weighted average number of shares of common stock (“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,
	2014		2013		2012
	(In thousands, except per share amounts)
Numerator:
Net income attributed to common shareholders	$	68,823	$	66,405	$	182,350


Denominator:
Weighted average common shares outstanding - basic		53,838		53,038		52,008

Effect of potentially dilutive securities:
Stock options		2,245		2,096		1,979
Restricted stock		430		233		52

Weighted average common shares outstanding - diluted		56,513		55,367		54,039


Earnings per common share:
Basic	$	1.28	$	1.25	$	3.51

Diluted	$	1.22	$	1.20	$	3.37

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


	Years Ended December 31,
	2014		2013		2012
	(In thousands)

Basic earnings per share:
Unvested restricted stock		1,448		1,194		748

Diluted earnings per share:
Anti-dilutive stock options		201		1,054		1,193
Anti-dilutive restricted stock		3		164		30

Potentially dilutive securities excluded as anti-dilutive		204		1,218		1,223

Recent Accounting Pronouncements. In August 2014, the Financial Accounting Standards Board (“FASB”) issued guidance on disclosures of uncertainties about an entity’s ability to continue as a going concern. The guidance requires management’s evaluation of whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. This assessment must be made in connection with preparing financial statements for each annual and interim reporting period. Management’s evaluation should be based on the relevant conditions and events that are known and reasonably knowable at the date the financial statements are issued. If conditions or events raise substantial doubt about the entity’s ability to continue as a going concern, but this doubt is alleviated by management’s plans, the entity should disclose information that enables the reader to understand what the conditions or events are, management’s evaluation of those conditions or events and management’s plans that alleviate that substantial doubt. If conditions or events raise substantial doubt and the substantial doubt is not alleviated, the entity must disclose this in the footnotes. The entity must also disclose information that enables the reader to understand those conditions or events, management’s evaluation of those conditions or events, and management’s plans to alleviate the substantial doubt. The guidance is effective for annual periods and interim periods within those annual periods beginning after December 15, 2016. The Company does not expect the adoption of this new guidance to have a material impact on its financial statements or its financial statement disclosures.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, 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. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect ASU 2014-09 will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has the effect of the standard on ongoing financial reporting been determined.

In April 2014, the FASB issued new guidance intended to change the criteria for reporting discontinued operations while enhancing disclosures for discontinued operations, which changes the criteria and requires additional disclosures for reporting discontinued operations. The guidance is effective for all disposals of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within annual periods beginning on or after December 15, 2015. The Company does not expect the adoption of this new guidance to have a material impact on its financial statements or its financial statement disclosures.

Reclassifications and immaterial adjustment. Certain reclassifications have been made to prior period consolidated financial statements to conform to current period presentations. Additionally, an immaterial adjustment has been made to the Company’s consolidated statement of cash flows for the years ended December 31, 2013 and December 31, 2012 to decrease previously reported operating cash flows and increase previously reported investing cash flows by $6.2 million and $0.8 million, respectively, to properly reflect the change in accrued capital expenditures on the consolidated statement of cash flows as a supplemental non-cash investing activity. These adjustments had no impact to the Company’s consolidated balance sheet or consolidated statement of operations for the year ended December 31, 2013.

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Note 2 - Long-Term Debt and Capital Lease Obligations

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


	As of December 31,
	2014			2013

Senior secured revolving credit facility maturing on April 19, 2016	$	315,000		$	150,000
Capital leases		38,748			17,065

Total debt and capital lease obligations		353,748			167,065

Less: amount maturing within one year		(3,873	)		(2,860	)


Long-term debt and capital lease obligations	$	349,875		$	164,205

Credit Facility

On April 19, 2011, the Company entered into a five-year senior secured revolving credit agreement which, as amended on June 5, 2012, had a borrowing base of $400.0 million (the “Credit Facility”). The sublimit for letters of credit is $200.0 million and the sublimit for swing line loans is $25.0 million. In November 2014, the Company exercised the accordion feature of the Credit Facility, increasing the total borrowing base under the facility by $100.0 million to a total of $500.0 million. Loans under the Credit Facility are denominated in U.S. dollars and will mature on April 19, 2016. Outstanding loans bear interest at either LIBOR or a base rate, at the Company’s election, plus an applicable margin that ranges from 1.25% to 2.00% for base rate loans and from 2.25% to 3.00% for LIBOR loans, based upon the Company’s ratio of funded indebtedness to EBITDA for the Company on a consolidated basis. The Company is also required to pay a quarterly commitment fee at an annual rate of 0.5% on the unused portion of the Credit Facility.

As of December 31, 2014, $315.0 million was outstanding under the Credit Facility, along with $2.0 million in letters of credit, leaving $183.0 million available for borrowing. All obligations under the Credit Facility are guaranteed by the Company’s wholly-owned domestic subsidiaries, other than immaterial subsidiaries. The weighted average interest rate as of December 31, 2014 was 3.0%.

The Credit Facility contains customary affirmative and negative covenants, including but not limited to (1) an Interest Coverage Ratio of not less than 3.00 to 1.00 and (2) a Consolidated Leverage Ratio of not greater than 3.25 to 1.00. As of December 31, 2014, the Company was in compliance with all financial covenants.

Capitalized terms used in this Note 2 – Long-Term Debt and Capital Lease Obligations but not defined herein are defined in the Credit Facility.

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 $0.9 million at December 31, 2014. 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 $1.2 million at December 31, 2014. 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.

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As of December 31, 2014, the future minimum lease payments under the Company’s capital leases are as follows (in thousands)


Years Ending December 31,

2015	$	4,875
2016		3,734
2017		3,584
2018		3,685
2019		3,785
Thereafter		25,272

	$	44,935

Note 3 – Acquisitions

Acquisition of Tiger

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

Acquisition of Casedhole Solutions

On June 7, 2012, the Company acquired all of the outstanding equity interests of Casedhole Holdings, Inc. and its operating subsidiary, Casedhole Solutions, Inc. (collectively, “Casedhole Solutions”), which was accounted for using the purchase method of accounting. The results of Casedhole Solutions’ operations since the date of the acquisition have been included in the Company’s consolidated financial statements and are presented in Note 11 – Segment Information. The acquisition of Casedhole Solutions added cased-hole wireline and other complementary services to the Company’s existing service lines and expanded its geographic presence and customer base. Total consideration paid by the Company consisted of approximately $273.4 million in cash, net of cash acquired of approximately $7.4 million. This included a final working capital adjustment of $1.5 million that was paid in September 2012. The Company funded the acquisition through $220.0 million drawn from the Credit Facility, with the remainder paid from cash on hand.

- 19 -

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


Current assets	$	49,619
Property and equipment		73,204
Goodwill		131,455
Other intangible assets		105,600
Other assets		1,459

Total assets acquired	$	361,337


Current liabilities	$	23,081
Capital lease obligations		4,895
Deferred income taxes		52,602

Total liabilities assumed	$	80,578

Net assets acquired	$	280,759

Other intangible assets consist of customer relationships of $80.4 million, amortizable over 15 years, trade name of $23.6 million, amortizable over 10 years, and non-compete agreements of $1.6 million, amortizable over four years. The amount allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. The goodwill and other intangible assets are not tax deductible.

The following unaudited pro forma results of operations have been prepared as though the Casedhole Solutions acquisition was completed on January 1, 2011. Pro forma amounts are based on the purchase price allocation of the acquisition and are not necessarily indicative of results that may be reported in the future or of results that might have been achieved had the acquisition been completed on January 1, 2011 (in thousands, except per share data):


	Years Ended December 31,
	2012		2011

Revenues	$	1,205,864	$	886,721
Net income		194,716		167,842

Net income per common share:
Basic	$	3.74	$	3.40
Diluted		3.60		3.31

In preparing the pro forma financial information, the Company added $0.3 million and $0.6 million of depreciation expense for the years ended December 31, 2012 and 2011, respectively. Amortization expense for the amortization of intangible assets of $3.5 million and $8.1 million was added for the years ended December 31, 2012 and 2011, respectively. Selling, general and administrative expenses were reduced by $3.3 million related to costs incurred in connection with the acquisition for the year ended December 31, 2012. Interest expense was increased by $1.5 million and $1.9 million for the years ended December 31, 2012 and 2011, respectively. Income tax expense was reduced by $2.5 million and $3.5 million for the years ended December 31, 2012 and 2011, respectively. The amount of revenue and earnings of Casedhole Solutions since the acquisition date included in the consolidated statement of operations for the year ended December 31, 2012 are presented in “Note 11 – Segment Information.”

Other Acquisitions

In April 2013, the Company acquired all of the outstanding common stock 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.

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Note 4 – Income Taxes

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


	Years Ended December 31,
	2014			2013			2012

Current provision:
Federal	$	11,184		$	22,870		$	75,205
State		1,310			1,930			3,948

Total current provision		12,494			24,800			79,153

Deferred (benefit) provision:
Federal		31,978			14,864			16,199
State		2,036			1,705			(273	)
Foreign		(829	)		(56	)		—

Total deferred provision		33,185			16,513			15,926


Provision for income taxes	$	45,679		$	41,313		$	95,079

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


	Years Ended December 31,
	2014			2013			2012

Federal statutory rate		35.0	%		35.0	%		35.0	%
State taxes, net of federal benefit		3.0	%		2.8	%		1.4	%
Domestic production activities deduction		-1.0	%		-1.8	%		-2.6	%
Effect of foreign losses		2.4	%		0.7	%		—
Other		0.5	%		1.7	%		0.5	%

Effective income tax rate		39.9	%		38.4	%		34.3	%

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


	As of December 31,
	2014			2013

Deferred tax assets:
Accrued liabilities	$	5,419		$	635
Allowance for doubtful accounts		822			609
Stock-based compensation		1,027			335
Other		838			429

Current deferred tax assets		8,106			2,008

Stock-based compensation		16,896			14,577
Net operating losses		1,181			750
Accrued liabilities		69			93
Other		—			123

Non-current deferred tax assets		18,146			15,543


Total deferred tax assets		26,252			17,551
Valuation allowance		—			—

Total deferred tax assets, net		26,252			17,551

Deferred tax liabilities:
Current deferred tax liability		—			(286	)

Depreciation on property, plant and equipment		(161,782	)		(113,584	)
Amortization of goodwill and intangible assets		(49,704	)		(47,174	)

Non-current deferred tax liabilities		(211,486	)		(160,758	)


Net deferred tax liability	$	(185,234	)	$	(143,493	)

The Company has approximately $0.8 million of state net operating loss carryforwards (“NOL’s”) which expire in various years between 2025 and 2032, and $4.6 million of Canadian NOL’s which will expire in 2033. The Company believes that it is more likely than not that these NOL’s will be utilized and no valuation allowance has been provided.

The Company has identified its major taxing jurisdictions as the United States of America and Texas. The Company’s U.S. federal income tax returns for the years 2011 through 2013 remain open to examination under the applicable federal statute of limitations provisions. The Company’s Texas franchise tax returns for the years 2010 through 2014 remain open to examination under the applicable Texas statute of limitations provisions. The Company’s 2011, 2012 and 2013 Louisiana tax returns are currently under examination.

Note 5 – Stockholders’ Equity

On October 30, 2013, the Company announced that the Board of Directors authorized a common stock repurchase program, pursuant to which the Company may repurchase up to an aggregate $100 million of C&J’s common stock through December 31, 2015 (the “Repurchase Program”). Any repurchases will be implemented through open market transactions or in privately negotiated transactions, in accordance with applicable securities laws. The timing, price, and size of any repurchases will be made at the Company’s discretion and will depend upon prevailing market prices, general economic and market conditions, the capital needs of the business and other considerations. The Repurchase Program does not obligate the Company to acquire any particular amount of stock and any repurchases may be commenced or suspended at any time without notice. As of December 31, 2014, there have been no repurchases of common stock made under this program.

Note 6 - Stock-Based Compensation

The C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (the “2012 LTIP”) provides for the grant of stock-based awards to the Company’s officers, employees, consultants and non-employee directors. The following types of awards are available for issuance under the 2012 LTIP: incentive stock options and nonqualified stock options; stock appreciation rights; restricted stock; restricted stock units; dividend equivalent rights; phantom stock units; performance awards; and share awards. To date, only

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nonqualified stock options and restricted stock have been awarded under the 2012 LTIP. Under the 2012 LTIP, all stock option awards have been granted with an exercise price equal to the market price of the Company’s stock at the grant date. Those awards generally vest over three years of continuous service with one-third vesting on the first, second, and third anniversaries of the option’s grant date. The option awards expire on the tenth anniversary of the date of grant.

To the extent permitted by law, the participant of an award of restricted stock will have all of the rights of a stockholder with respect to the underlying shares of common stock, 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 stock will be deferred until the lapsing of the restrictions imposed on the shares and will be held by the Company for the account of the participant (either in cash or to be reinvested in shares of restricted stock) until such time. Payment of the deferred dividends and accrued interest, if any, shall be made upon the lapsing of restrictions on the shares of restricted stock, and any dividends deferred in respect of any shares of restricted stock shall be forfeited upon the forfeiture of such shares of restricted stock.

A total of 4.3 million shares of common stock were authorized and approved for issuance under the 2012 LTIP, subject to certain adjustments. This number of shares is subject to appropriate 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. This number of shares may also increase due to the termination of an award granted under the 2012 LTIP, or under the Company’s Prior Plans (as defined below), by expiration, forfeiture, cancellation or otherwise without the issuance of the shares of common stock. Approximately 2.6 million shares were available for issuance under the 2012 LTIP as of December 31, 2014.

Prior to the approval of the 2012 LTIP, the Company adopted and maintained the C&J Energy Services, Inc. 2010 Stock Option Plan (the “2010 Plan”). The Company’s 2010 Plan allowed for the grant of non-statutory stock options and incentive stock options to its employees, consultants and outside directors for up to 5.7 million shares of common stock. Under the 2010 Plan, option awards were generally granted with an exercise price equal to the market price of the Company’s stock at the grant date. Those option awards generally vest over three years of continuous service with one-third vesting on the first, second, and third anniversaries of the option’s grant date. Certain option awards provide for accelerated vesting if there is a change in control, as defined in the 2010 Plan. The options expire on the tenth anniversary of the date of grant.

In connection with the approval of the 2012 LTIP, on May 29, 2012, the 2010 Plan was amended to provide, among other things, that (i) no additional awards would be granted under the 2010 Plan on or after May 29, 2012, (ii) all awards outstanding under the 2010 Plan as of May 29, 2012 would continue to be subject to the terms of the 2010 Plan and the applicable award agreement, and (iii) if and to the extent an award originally granted pursuant to the 2010 Plan is terminated by expiration, forfeiture, cancellation or otherwise without the issuance of shares of common stock, any and all shares of common stock associated with such award shall become available to be granted pursuant to a new award under the terms of the 2012 LTIP.

Prior to December 23, 2010, all options granted to employees were granted under the C&J Energy Services, Inc. 2006 Stock Option Plan (the “2006 Plan” and, together with the 2010 Plan, the “Prior Plans”). On December 23, 2010, the 2006 Plan was amended to provide, among other things, that (i) no additional awards would be granted under the 2006 Plan, (ii) all awards outstanding under the 2006 Plan would continue to be subject to the terms of the 2006 Plan and the applicable award agreement, and (iii) all unvested options under the 2006 Plan would immediately vest and become exercisable in connection with the completion of a private placement of common stock that occurred in December 2010. On May 29, 2012, the 2006 Plan was further amended to provide, among other things, that if and to the extent an award originally granted pursuant to the 2006 Plan is terminated by expiration, forfeiture, cancellation or otherwise without the issuance of shares of common stock, any and all shares of common stock associated with such award shall become available to be granted pursuant to a new award under the terms of the 2012 LTIP.

Stock Options

The fair value of each option award granted under the 2012 LTIP and the Prior Plans is estimated on the date of grant using the Black-Scholes option-pricing model. 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. For options granted prior to the Company’s initial public offering (“IPO”), which closed on August 3, 2011, the calculation of the Company’s stock 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.

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


		Year Ended December 31, 2012

Expected volatility		65% - 75%
Expected dividends		None
Exercise price		$16.88 - $18.89
Expected term (in years)		6
Risk-free rate		0.9% - 1.4%

The weighted average grant date fair value of options granted during the year ended December 31, 2012 was $11.45.

A summary of the Company’s stock option activity for the year ended December 31, 2014 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, 2014		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

Exercisable at December 31, 2014		5,024		$	11.65		5.38	$	21,395

The total intrinsic value of options exercised during the years ended December 31, 2014 and 2013 was $3.2 million and $13.0 million, respectively. As of December 31, 2014, there was $0.2 million of total unrecognized compensation cost related to outstanding stock options. That cost is expected to be recognized over a weighted-average period of 0.4 years.

Restricted Stock

Restricted stock is valued based on the closing price of the Company’s common stock on the date of grant. During the year ended December 31, 2014, approximately 0.8 million shares of restricted stock were granted to employees and non-employee directors under the 2012 LTIP at fair market values ranging from $14.46 to $33.14 per share. During the year ended December 31, 2013, approximately 0.7 million shares of restricted stock were granted to employees, consultants and non-employee directors under the 2012 LTIP at fair market values ranging from $19.25 to $23.69 per share.

- 24 -

A summary of the status and changes during the year ended December 31, 2014 of the Company’s shares of non-vested restricted stock is presented below:


	Shares			Weighted Average Grant-Date Fair Value
	(in thousands)
Non-vested at January 1, 2014		1,133		$	21.63
Granted		798			24.65
Forfeited		(75	)		23.14
Vested		(479	)		21.39

Non-vested at December 31, 2014		1,377		$	23.39

As of December 31, 2014 and 2013, respectively, there was $18.7 million and $15.8 million of total unrecognized compensation cost related to shares of restricted stock. That cost is expected to be recognized over a weighted-average period of 1.7 years. The weighted-average grant-date fair value per share of restricted stock granted during the years ended December 31, 2014 and 2013, respectively, was $24.65 and $23.37.

As of December 31, 2014, the Company had 6.4 million stock options and shares of restricted stock 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. As of December 31, 2013, the Company had 6.4 million of stock options and shares of restricted stock outstanding to employees and non-employee directors, 1.1 million of which were issued under the 2006 Plan, 4.1 million were issued under the 2010 Plan and the remaining 1.2 million were issued under the 2012 Plan.

Stock-based compensation expense was $18.4 million, $22.6 million and $18.0 million for the years ended December 31, 2014, 2013 and 2012, respectively, and is included in selling, general and administrative expenses on the consolidated statements of operations. The total income tax benefit recognized in the consolidated statements of operations in connection with stock-based compensation expense was approximately $6.4 million, $7.9 million and $6.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Note 7 – Related Party Transactions

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, 2013 and 2012, purchases from these vendors totaled $7.4 million, $3.7 million and $2.6 million, respectively. Amounts payable to these vendors at December 31, 2014 and 2013 were $0.9 million and $0.1 million, respectively.

The Company purchases certain of its equipment on an arm’s length basis from vendors affiliated with a member of its Board of Directors. December 31, 2014, 2013 and 2012, purchases from these vendors were $5.7 million, $3.8 million and $14.7 million, respectively. Amounts payable to these vendors at December 31, 2014 and 2013 were $1.5 million and $0.9 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, 2014, 2013 and 2012, purchases from these vendors were $1.0 million, $1.7 million and $1.3 million, 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, 2014 and 2013, purchases from this vendor were $21.8 million and $7.6 million, respectively.

The Company obtains machined parts from a vendor which is affiliated with several of its employees. For the years ended December 31, 2014 and 2013, purchases from this vendor totaled $0.4 million and $0.4 million, respectively.

Note 8 – Business Concentrations

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. Concentrations of credit risk with respect to accounts receivable are limited because the

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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 51.1%, 64.6% and 81.0% of the Company’s consolidated revenue for the years ended December 31, 2014, 2013 and 2012, respectively. 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. For the year ended December 31, 2012, revenue from three customers individually represented 19.1%, 15.6% and 12.9% 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 2014, 2013 or 2012. Revenue was earned from each of these customers within the Company’s Completion Services segment.

Note 9 - 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.

On February 9, 2013, the Company signed an agreement to settle a dispute arising from a lawsuit filed in 2011 in which the Company and certain current and former equity holders, including certain executive officers, were named as defendants. The settlement agreement stipulated that the Company pay $5.9 million for a full release of any further liability. The settlement amount was recorded in 2012 and reflected in accrued expenses on the consolidated balance sheet as of December 31, 2012 and in selling, general and administrative expenses on the consolidated statement of operations for the year then ended.

Service Equipment and Other Capital Expenditures

The Company has agreed to purchase service equipment and other capital assets for $15.9 million as of December 31, 2014. The Company expects to fulfill these commitments during 2015.

Inventory and Materials

The Company has entered into contractual agreements or commitments to purchase inventory and other materials for $72.0 million as of December 31, 2014. The Company expects to fulfill these commitments over the next 5 years.

Operating Leases

The Company leases certain property and equipment under non-cancelable operating leases. The remaining terms of the operating leases generally range from 12 months to 7 years.

Lease expense under all operating leases totaled $14.0 million $14.6 million and $12.3 million for the years ended December 31, 2014, 2013 and 2012, 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,

2015	$	7,760
2016		5,318
2017		3,308
2018		2,479
2019		1,648
Thereafter		5,474

	$	25,987

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Note 10 – 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, 2014, 2013 and 2012 totaled $2.3 million, $1.9 million and $1.0 million, respectively.

Note 11 - Segment Information

In accordance with Accounting Standards Codification (“ASC”) No. 280, Segment Reporting (“ASC 280”), 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.

This note has been revised and recast from the note to the consolidated financial statements originally filed in the Company’s Form 8-K/A filed with the Securities and Exchange Commission on May 29, 2015 to reflect the Company’s revised segment structure that became effective in March 2015. 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”). 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, specifically 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 recast the segment information below to reflect the new reportable segment structure in order to conform to the current year presentation. The following is a description of the reportable segments:

Completion Services

The Company provides hydraulic fracturing, coiled tubing, cased-hole wireline, pumpdown and other well stimulation services, as well as nitrogen, pressure pumping and thru-tubing services through its Completion Services segment.

Well Support Services

The Company provides a well servicing line, including maintenance, workover and plug and abandonment services, as well as fluid management and rental tool services through its Well Support Services segment. This segment did not exist prior to the Merger.

Other Services

The Company’s smaller service lines and divisions, including cementing, directional drilling, equipment manufacturing, specialty chemical supply and research and technology are provided through the Other Services segment. The following tables set forth certain financial information with respect to the Company’s reportable segments. Included in “Other Services” are intersegment eliminations and costs associated with activities of a general corporate nature.

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	Completion Services		Other Services			Total

Year Ended December 31, 2014
Revenue from external customers	$	1,581,712	$	26,232		$	1,607,944
Inter-segment revenues		122		(122	)		—
Adjusted EBITDA		344,985		(91,476	)		253,509
Depreciation and amortization		101,554		6,591			108,145
Operating income (loss)		243,171		(119,427	)		123,744
Capital expenditures		293,635		22,083			315,718
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
Inter-segment revenues		205		(205	)		—
Adjusted EBITDA		254,231		(63,557	)		190,674
Depreciation and amortization		73,279		1,424			74,703
Operating income (loss)		180,201		(65,986	)		114,215
Capital expenditures		152,120		5,867			157,987
As of December 31, 2013
Total assets	$	1,002,417	$	129,883		$	1,132,300
Goodwill		191,794		14,004			205,798
Year Ended December 31, 2012
Revenue from external customers	$	1,070,086	$	41,415		$	1,111,501
Inter-segment revenues		—		—			—
Adjusted EBITDA		375,102		(38,390	)		336,712
Depreciation and amortization		44,549		2,363			46,912
Operating income (loss)		329,718		(47,188	)		282,530
Capital expenditures		183,137		(958	)		182,179
As of December 31, 2012
Total assets	$	943,336	$	69,421		$	1,012,757
Goodwill		191,794		4,718			196,512

Management evaluates segment performance and allocates resources based on total earnings before net interest expense, income taxes, depreciation and amortization, net gain or loss on disposal of assets, transaction 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 and net income, 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, which is the nearest comparable U.S. GAAP financial measure (in thousands).


	Years Ended December 31,
	2014			2013			2012

Adjusted EBITDA	$	253,509		$	190,674		$	336,712
Interest expense, net		(9,840	)		(6,550	)		(4,996	)
Income tax expense		(45,679	)		(41,313	)		(95,079	)
Depreciation and amortization		(108,145	)		(74,703	)		(46,912	)
Gain (loss) on disposal of assets		17			(527	)		(692	)
Transaction costs		(20,159	)		(306	)		(833	)
Legal settlement		—			—			(5,850	)
Insurance settlement		(880	)		—			—
Inventory write-down		—			(870	)		—

Net income	$	68,823		$	66,405		$	182,350

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Note 12 – Quarterly Financial Data (unaudited)

Summarized quarterly financial data for the years ended December 31, 2014 and 2013 are presented below (in thousands, except per share amounts).


	Quarters Ended
	March 2014		June 2014		September 2014		December 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


	Quarters Ended
	March 2013		June 2013		September 2013		December 2013
Revenue	$	276,051	$	266,956	$	261,931	$	265,384
Operating income		40,418		34,855		23,459		15,483
Income before income taxes		38,824		33,236		21,921		13,737
Net income		25,143		20,847		13,125		7,290
Net income per common share:
Basic	$	0.48	$	0.39	$	0.25	$	0.14
Diluted	$	0.46	$	0.38	$	0.24	$	0.13

Note 13 – Subsequent Events

Merger with the Completion and Production Services Business of Nabors Industries, Ltd.

On June 25, 2014, the Company entered into a definitive merger agreement (the “Merger Agreement”) with Nabors Industries Ltd. (“Nabors”) to combine with the Completion and Production Services Business (the “C&P Business”) of Nabors. Upon the closing of the merger, Nabors received total consideration comprised of approximately $688 million in cash and approximately 62.5 million common shares in the newly combined entity. The estimated value of such consideration to be paid to Nabors at closing was $1.5 billion as of February 13, 2015, with the common shares valued based on the closing price on the NYSE for C&J’s common stock on such date.

Immediately following the closing of the merger, former C&J stockholders own approximately 47% of the issued and outstanding common shares of the newly combined entity (49.75% on a fully diluted basis) and Nabors owns approximately 53% of the issued and outstanding common shares (50.25% on a fully diluted basis).

The merger was accounted for using the acquisition method of accounting for business combinations. In applying the acquisition method, it was determined that the Company will possess a controlling financial interest and that the business combination should therefore be treated as a reverse acquisition with the Company as the accounting acquirer.

On March 24, 2015, C&J and Nabors completed the combination of C&J with the C&P Business. The resulting combined company has been renamed C&J Energy Services Ltd.

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C&J Energy Services, Inc. - FORM 8-K/A - EX-99.1 - July 15, 2015

Attached files

C&J Energy Services, Inc. Reports