Exhibit 99.6

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”).

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/A.

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/A, 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.

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/A.

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.

 

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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.

 

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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.

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.

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.

 

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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.

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

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

 

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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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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

 

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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.

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

As of December 31, 2014, we operated in three reportable operating segments: Stimulation and Well Intervention Services; Wireline Services; and Equipment Manufacturing. In line with the growth of our business, we routinely evaluate our reportable operating segments and we believe that these three segments are appropriate and consistent with how we manage our business and view the markets we serve. Our operating segments are described in more detail below. For financial information about our segments, including revenue from external customers and total assets by segment, see “Note 11 – Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data.”

Stimulation and Well Intervention Services

Our Stimulation and Well Intervention Services segment provides (i) hydraulic fracturing services and (ii) coiled tubing and other well stimulation services, as well as directional drilling services.

Hydraulic Fracturing Services. Our customers use our hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability, which restricts the natural flow of hydrocarbons. Hydraulic fracturing involves pumping a fluid down a well casing or tubing at sufficient pressure to cause the underground producing formation to fracture, allowing the oil or natural gas to flow more freely. A propping agent, or proppant, is suspended in the fracturing fluid and used to prop the fractures open. Proppants generally consist of sand, bauxite, resin-coated sand or ceramic particles and other engineered proprietary materials. The extremely high pressure required to stimulate wells in the regions in which we operate presents a challenging environment for achieving a successfully fractured horizontal well. As a result, an important element of the services we provide to producers is designing the optimum well completion, which includes determining the proper fluid, proppant and injection specifications to maximize production. Our engineering staff also provides technical evaluation, job design and fluid recommendations for our customers as an integral element of our fracturing service.

Our operating strategy for this service line includes maintaining high asset utilization levels to maximize revenue generation. To implement this strategy, we have focused on those markets historically requiring significant pumping services, substantial hydraulic horsepower (“HHP”) capacity, and large volumes of consumables. Our hydraulic fracturing assets are concentrated in operating areas characterized by complex, technically demanding, service intensive work with higher HHP requirements. We also target customers that favor 24-hour operations and multi-well pad drilling as part of our effort to maximize revenue generation. However, even if we are able to obtain a job-mix weighted towards greater

 

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revenue generating activities, this may not result in improved profitability. Given the cyclical nature of activity drivers in the U.S. land market areas, coupled with the high labor intensity and costs of these services, operating margins can fluctuate widely depending on supply and demand at a given point in the cycle.

As of the year ended December 31, 2014, our hydraulic fracturing services consisted of more than 440,000 total HHP capacity, having deployed over 120,000 incremental HHP capacity over the course of the year to take advantage of increasing service-intensive completion activity in our primary operating areas and strong customer demand. As a result of our strategic planning and the flexibility provided by our in-house manufacturing capabilities, we were able to quickly secure work for each fleet with high activity operators immediately after deploying the equipment. We consider HHP to be deployed at the point that we have taken delivery of the equipment and made it available for immediate operations, regardless of whether we have secured work for the equipment at that time.

HHP is a measure of the pressure pumping capabilities of a pressure pump unit and each of our pressure pump units has approximately 2,000 HHP of pressure pumping capacity. We measure capacity for our hydraulic fracturing services based on the aggregate HHP in our hydraulic fracturing fleet that we have deployed, because the amount of HHP capacity that we have available for operations generally correlates to our ability to generate revenue. The HHP requirements for a hydraulic fracturing job varies widely based on numerous factors that are outside of our control, including the geological characteristics of the reservoir formation, the well structure and customer specifications. We have performed jobs with as little as 2,000 HHP, and jobs that have required as much as 44,000 HHP.

We generate revenue for the services provided and consumables (such as fluids and proppants) used in our hydraulic fracturing operations on a per job basis, which can consist of one or more fracturing stages. The number of fracturing stages, and the size and intensity of those fracturing stages, will vary significantly from job-to-job based on a number of factors, including the geological characteristics of the reservoir formation, the well structure and customer specifications. This directly impacts the amount of HHP capacity and hours of services provided and volume of consumables used in a hydraulic fracturing job. We typically charge prevailing market prices per hour for our services and charge at cost plus an agreed-upon markup for consumables used. We may also charge fees for the mobilization and set-up of equipment, any additional equipment used on the job, and other miscellaneous consumables. Generally, these fees and other charges vary depending on the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed. Given these variables, revenue and operating margins may vary substantially from job-to-job, from customer-to-customer and from month-to-month.

We measure our activity levels, or utilization, by the total number of days that our aggregate HHP capacity works on a monthly basis. We generally consider our HHP capacity to be working such days that it is at or in transit to a job location, regardless of the number of hours worked or whether it generated any revenue during such time. Our management team monitors this measure of asset utilization for purposes of assessing our overall activity levels and customer demand, and efficiently allocating our assets. However, asset utilization is not indicative of our financial and/or operational performance and should not be given undue reliance. During the year ended December 31, 2014, our aggregate HHP capacity was approximately 94% utilized and our hydraulic fracturing operations contributed $985.0 million, or 61.3%, to our consolidated revenue for the year ended December 31, 2014.

Coiled Tubing and Other Well Stimulation Services. Our customers use our coiled tubing services to perform various functions associated with well-servicing operations and to facilitate completion of new and existing wells. Coiled tubing services involve the use of a continuous metal pipe spooled onto a large reel which is then deployed into oil and natural gas wells to perform various applications. We believe coiled tubing has become a preferred method of well completion, workover and maintenance projects due to its speed, ability to handle heavy-duty jobs across a wide spectrum of pressure environments, safety and ability to perform services without having to shut-in a well.

 

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As of December 31, 2014, we operated 35 coiled tubing units, having deployed 11 incremental coiled tubing units and related ancillary equipment over the course of the year. Two of our coiled tubing units were positioned in Saudi Arabia in early 2014 to service our first international contract.

We consider a coiled tubing unit to be deployed at such point that we have taken delivery of the equipment and made it available for immediate operations, regardless of whether we have secured work for the equipment at that time. We measure capacity for our coiled tubing services primarily based on the total number of coiled tubing units that we have deployed, as the amount of coiled tubing units that we have available for operations generally correlates to our ability to generate revenue. Our coiled tubing services are well-established in some of the most active basins in the United States and we are committed to further grow this business in terms of capacity, geographic reach and market share.

We generate revenue for the services provided and consumables (such as stimulation fluids, nitrogen and coiled tubing materials) used in our coiled tubing operations on a per job basis. The type and amount of required services and service intensity will vary significantly from job-to-job based on a number of factors, including the geological characteristics of the reservoir formation, the well structure and customer specifications. We typically charge prevailing market prices per hour for our services and charge at cost plus an agreed-upon markup for any consumables used in performing our services. We may also charge fees for mobilization and set up of equipment, the personnel on the job, any additional equipment used on the job and other miscellaneous consumables. Generally, these fees and other charges vary depending on the type of service to be performed and the equipment and personnel required for the job, as well as competitive factors and market conditions in the region in which the services are performed. Given these variables, revenue and operating margins may vary substantially from job-to-job.

We measure our activity levels, or utilization, for our coiled tubing services primarily by the total number of days that our aggregate coiled tubing units work on a monthly basis. We generally consider a coiled tubing unit to be working such days that it is at a customer job location, regardless of the number of hours worked or the amount of revenue generated during such time. Our management team monitors this measure of asset utilization for purposes of assessing our overall activity levels and customer demand, and efficiently allocating our assets. However, asset utilization is not indicative of our financial and/or operational performance and should not be given undue reliance. During the year ended December 31, 2014, our coiled tubing services were approximately 75% utilized, based on available working days per month, which excludes scheduled maintenance days, and our coiled tubing operations contributed $176.3 million, or 11.0%, to our consolidated revenue for the year ended December 31, 2014.

Our other well stimulation services primarily include nitrogen, pressure pumping and thru-tubing services, as well as our recently launched directional drilling services line. Additionally we blend and supply specialty chemicals for completion and production services, and also manufacture and provide downhole tools and related directional drilling technology and data acquisition control systems. These products are provided to third-party customers in the energy services industry and are also used in our operations and equipment. After an evaluation of these businesses, it was determined that each is appropriately accounted for in our Stimulation and Well Intervention Services segment.

Collectively, our other well stimulation services contributed $25.3 million, or 1.5%, to our consolidated revenue, for the year ended December 31, 2014, with the substantial majority generated from our nitrogen, pressure pumping and thru-tubing services.

Wireline Services

Our Wireline Services segment provides cased-hole wireline, pumpdown and other complementary services, including logging, perforating, pipe recovery and pressure testing services. We have aggressively grown this business and increased market share since our entry into this service line through our June 2012 acquisition of Casedhole Solutions, Inc. (“Casedhole Solutions”). During 2014, we further expanded our wireline capabilities through the deployment of new equipment, as well as the second quarter acquisition of Tiger, a leading provider of wireline services on the U.S. West Coast. See “Note 3 – Acquisitions” in Part II, Item 8 “Financial Statements and Supplementary Data” for further discussion regarding the acquisitions of Casedhole Solutions and Tiger.

 

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As of December 31, 2014, we operated 92 wireline units and 53 pumpdown units, as well as pressure control and other ancillary equipment. We deployed 23 incremental wireline units and 20 new incremental pumpdown units during 2014.

We consider a wireline unit to be deployed at the point that we have taken delivery of the equipment and made it available for immediate operations, regardless of whether we have secured work for the equipment at that time. We measure capacity for our wireline services primarily based on the total number of wireline units that we have deployed, as the wireline units that we have available for operations generally correlates to our ability to generate revenue. We generate revenue for our wireline services on a per job basis at agreed-upon spot market rates. Wireline jobs are short-term in nature, typically lasting only a few hours to a few days. We measure our activity levels, or utilization, for our wireline services primarily by the total number of days that our aggregate wireline units work on a monthly basis. We generally consider a wireline unit to be working such days that it is at or in transit to a job location, regardless of the number of hours worked or whether it generated any revenue during such time. Our management team monitors this measure of asset utilization for purposes of assessing our overall activity levels and customer demand, and efficiently allocating our assets. However, utilization is not indicative of our financial and/or operational performance and should not be given undue reliance. During the year ended December 31, 2014, our wireline services were approximately 85% utilized, based on available working days per month, which excludes scheduled maintenance days, and our Wireline Services segment contributed $408.5 million, or 25.4%, to our consolidated revenue for the year ended December 31, 2014.

Equipment Manufacturing

We commenced our Equipment Manufacturing segment with the acquisition of Total E&S, Inc. in April 2011. Our Equipment Manufacturing segment manufactures, refurbishes and repairs equipment and provides oilfield parts and supplies for third-party customers in the energy services industry, as well as to fulfill the internal equipment demands of our Stimulation and Well Intervention Services and Wireline Services segments. This business continues to provide us with cash flow savings from intercompany purchases, including equipment manufacturing, repair and refurbishment, and also supports active management of parts and supplies purchasing. One of the many benefits provided by our in-house manufacturing capabilities is the ability to minimize the cost and ensure timely delivery of new equipment to meet customer demand. It also gives us the flexibility to timely respond to changes in market conditions and customer demand, which we believe provides a competitive advantage. This segment is key to our vertical integration efforts as it provides a means for us to integrate our strategic initiatives to implement technological developments and enhancements.

Our Equipment Manufacturing segment contributed $11.8 million in third-party revenue, or 0.7%, to our consolidated revenue, for the year ended December 31, 2014.

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.

 

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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.

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. Natural gas prices declined in 2009 and remained depressed through 2014, which resulted in decreased activity in the natural gas-driven markets. However, oil prices increased during the first half of 2011 and remained relatively stable through 2013. The sustained price disparity between oil and natural gas on a Btu basis led to the migration of equipment from basins that are predominantly gas-related, and as a result much of the horizontal drilling and completion related activity became concentrated in oily- and liquids-rich formations. The excess completion capacity into the oily- and liquids-rich regions and weakness in the price of natural gas led to increased competition among energy service companies in the oily regions, which negatively affected pricing and utilization levels for our services.

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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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.

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.

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.

 

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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.”

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 Stimulation and Well Intervention Services (“SWI”) segment contributed $403.2 million of additional revenue primarily from our hydraulic fracturing services and our Wireline Services segment contributed $129.7 million. The increased revenue for these two segments 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.

 

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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 SWI segment had $350.0 million of additional direct costs primarily from our hydraulic fracturing services and our Wireline Services segment contributed $69.0 million of additional direct costs, 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 Pending Nabors Transaction, 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 $16.9 million from our SWI segment due to the deployment of new, incremental hydraulic fracturing and coiled tubing equipment and $12.3 million from our Wireline Services segment 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.

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 a $156.9 million decrease in Stimulation and Well Intervention Services revenue primarily due to lower utilization and pricing for our hydraulic fracturing services, as well as a $33.0 million decrease in Equipment Manufacturing revenue due to lower demand as a result of excess equipment capacity in the energy services industry, and partially offset by $148.7 million in incremental Wireline Services revenue as a result of the acquisition of our wireline business in June 2012.

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 Wireline 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 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 Wireline Services, which we acquired in June 2012. During 2013, we expanded key administrative functions to support the growth of our business;

 

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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.

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 $27.8 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 $14.1 million in incremental Wireline Services costs due to the acquisition of our wireline business in June 2012 and $13.3 million in incremental Stimulation and Well Intervention Services 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.

 

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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. 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.

 

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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

 

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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.

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.

 

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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.

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 Stimulation and Well Intervention Services and Wireline Services segments, as well as a $33.2 million for 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.

 

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Net cash provided by financing activities increased $173.0 million primarily due to net borrowings from our credit facility to fund increased capital expenditures related to new equipment, the Tiger Acquisition, and transaction costs associated with the Pending Nabors Transaction.

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

 

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$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.

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.

 

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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.

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

 

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Manufacturing, all of which are consistent with the presentation of the Company’s three reportable segments. At the reporting unit level, the Company tests goodwill for impairment on an annual basis as of October 31 of each year, or when events or changes in circumstances, referred to as triggering events 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.

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.

 

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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

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.

 

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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 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. 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

 

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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.

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 Stimulation and Well Intervention Services and Wireline Services segments. 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

 

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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 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.

 

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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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