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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014.

or

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number: 001-35255

 

 

C&J Energy Services, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   20-567329

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

3990 Rogerdale Rd.

Houston, Texas 77042

(Address of principal executive offices)

(713) 325-6000

(Registrant’s telephone number, including area code)

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

 

Title of each class

 

Name of exchange on which registered

Common stock, par value $0.01   New York Stock Exchange

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

 

 

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x  No  ¨

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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

The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2014 (the last business day of the registrant’s most recently completed second fiscal quarter) based upon the closing price on the New York Stock Exchange on that date was approximately $1.7 billion.

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at February 13, 2015, was 55,208,701.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for its 2015 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2014, are incorporated by reference into Part III of this Form 10-K.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

         Page  

PART I

    

Item 1.

 

Business

     4   

Item 1A.

 

Risk Factors

     25   

Item 1B.

 

Unresolved Staff Comments

     39   

Item 2.

 

Properties

     40   

Item 3.

 

Legal Proceedings

     42   

Item 4.

 

Mine Safety Disclosures

     42   

PART II

    

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     43   

Item 6.

 

Selected Financial Data

     45   

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     46   

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

     73   

Item 8.

 

Financial Statements and Supplementary Data

     75   

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

     109   

Item 9A.

 

Controls and Procedures

     109   

Item 9B.

 

Other Information

     109   

PART III

    

Item 10.

 

Directors, Executive Officers and Corporate Governance

     110   

Item 11.

 

Executive Compensation

     110   

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     110   

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

     111   

Item 14.

 

Principal Accounting Fees and Services

     111   

PART IV

    

Item 15.

 

Exhibits, Financial Statement Schedules

     112   
 

Signatures

     116   

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Form 10-K”) includes certain statements and information that may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “plan,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “potential,” “would,” “may,” “probable,” “likely,” and similar expressions that convey the uncertainty of future events or outcomes, and the negative thereof, are intended to identify forward-looking statements. Forward-looking statements, which are not generally historical in nature, include those that express a belief, expectation or intention regarding our future activities, plans and goals and our current expectations with respect to, among other things:

 

    our future revenue, income and operating performance;

 

    our ability to sustain and/or improve our utilization, revenue and margins;

 

    our ability to maintain acceptable pricing for our services, including through term contacts and/or pricing agreements;

 

    our operating cash flows and availability of capital;

 

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

 

    our plan to continue to focus on international growth opportunities and our ability to successfully execute and capitalize on such opportunities;

 

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

 

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

 

    future capital expenditures;

 

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

 

    our ability to consummate the timing and success of the proposed combination with the completion and production services business of Nabors Industries Ltd.

Forward-looking statements are not assurances of future performance and actual results could differ materially from our historical experience and our present expectations or projections. These forward-looking statements are based on management’s current expectations and beliefs, forecasts for our existing operations, experience, expectations and perception of historical trends, current conditions, anticipated future developments and their effect on us, and other factors believed to be appropriate. Although management believes the expectations and assumptions reflected in these forward-looking statements are reasonable as and when made, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all). Our forward-looking statements involve significant risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Known material factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, risks associated with the following:

 

    the cyclical nature and volatility of the oil and gas industry, which impact the level of exploration, production and development activity and spending patterns by the oil and natural gas exploration and production industry;

 

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    a decline in, or substantial volatility of, crude oil and natural gas commodity prices, which generally leads to decreased spending by our customers and negatively impacts drilling and production activity and therefore reduces demand for our services and negatively impacts our results of operations, including potential impairment charges;

 

    a decline in demand for our services, including due to overcapacity and other competitive factors affecting our industry;

 

    pressure on pricing for our core services, including due to competition and industry and/or economic conditions, which may impact, among other things, our ability to implement price increases or maintain pricing on our core services;

 

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

 

    costs, delays, regulatory compliance requirements and other difficulties in executing our long-term growth strategy, including those related to expansion into new geographic regions and new business lines and the proposed combination with the completion and production services business of Nabors Industries Ltd.;

 

    the effects of future acquisitions on our business, including our ability to successfully integrate our operations and the costs incurred in doing so;

 

    business growth outpacing the capabilities of our infrastructure;

 

    adverse weather conditions in oil and/or gas producing regions;

 

    the effect of environmental and other governmental regulations on our operations, including the risk that future changes in the regulation of hydraulic fracturing could reduce or eliminate demand for our hydraulic fracturing services;

 

    the incurrence of significant cost and liabilities resulting from litigation;

 

    the incurrence of significant costs and liabilities resulting from our failure to comply, or our compliance with, new or existing environmental regulations or an accidental release of hazardous substances into the environment;

 

    expanding our operations overseas;

 

    the loss of, or inability to attract new, key management personnel;

 

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

 

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

 

    a shortage of qualified workers;

 

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

 

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

 

    accidental damage to or malfunction of equipment;

 

    an increase in interest rates;

 

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

 

    the proposed combination with the completion and production services business of Nabors Industries Ltd.

For additional information regarding known material factors that could affect our operating results and performance, please read (1) “Risk Factors” in Part I, Item 1A and (2) “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Form 10-K. Should one or more of these known material risks occur, or should the underlying assumptions prove incorrect, our actual results, performance, achievements or plans could differ materially from those expressed or implied in any forward-looking statement.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise, except as required by law.

 

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PART I

 

Item 1. Business

General Description of Our Business

C&J Energy Services, Inc. is a publicly traded corporation listed on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” We were founded in Texas in 1997 as a partnership, and reorganized as a Texas corporation in 2006. In December 2010, we converted to a Delaware corporation in connection with our initial public offering, which we completed in August 2011. References to “C&J,” the “Company,” “we,” “us” or “our” in this report are to C&J Energy Services, Inc. together with its consolidated subsidiaries.

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 10-K or any other report that we may file with or furnish to the SEC.

Pending Transaction to Combine with the Completion and Production Services Business of Nabors Industries, Ltd.

On June 25, 2014, we entered into an agreement and plan of merger (as amended from time to time, the “Merger Agreement”) with Nabors Industries Ltd., a Bermuda exempted company (“Nabors”), and Nabors Red Lion Limited, a Bermuda exempted company and a wholly owned subsidiary of Nabors (“Red Lion”), pursuant to which and subject to the terms thereof, a wholly owned Delaware subsidiary of Red Lion (“Merger Sub”) will merge with and into C&J with C&J surviving as a wholly owned subsidiary of Red Lion (the “Merger”). Prior to the Merger, Nabors will undergo a restructuring pursuant

 

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to a Separation Agreement dated as of June 25, 2014 by and between Nabors and Red Lion (as amended from time to time, the “Separation Agreement”) to separate Nabors’ completion and production services business in the U.S. and Canada (“C&P Business”) from the other businesses of Nabors, as a result of which Red Lion will own solely C&P Business (the “Separation”). The transactions contemplated by the Merger Agreement, Separation Agreement and the other agreements contemplated thereby are collectively referred to as the “Pending Nabors Transaction.”

In the Merger, each share of our common stock (other than any treasury shares and shares owned by Red Lion) will be converted into the right to receive one Red Lion common share. It is currently expected that, immediately following the closing of the Merger (“Closing”), former C&J stockholders will own approximately 47% of the issued and outstanding Red Lion common shares and Nabors will own approximately 53% of the issued and outstanding Red Lion common shares. At Closing, the authorized share capital of Red Lion will consist of 750 million common shares and 50 million preferred shares. When the Merger is completed, Red Lion (which will then own both the C&P Business and C&J) will be renamed C&J Energy Services, Ltd. and is expected to be listed on the NYSE under the ticker symbol CJES.

On February 6, 2015, Nabors and Red Lion, with the consent of C&J, entered into Amendment No. 1 to the Separation Agreement (the “Separation Agreement Amendment”). The Separation Agreement Amendment provides for, among other things, a $250 million reduction in the cash payment to be made by subsidiaries of Red Lion to Nabors in connection with the closing of the Merger. As a result, upon the closing of the Merger, Nabors will receive total consideration comprised of approximately $688 million in cash and approximately 62.5 million Red Lion common shares. The value of such consideration to be paid to Nabors at closing was $1.5 billion as of February 13, 2015, with the approximately 62.5 million Red Lion common shares valued based on the closing price on the NYSE for C&J’s common stock on such date. C&J has obtained commitments from certain financial institutions to provide debt financing to Red Lion and/or certain of its subsidiaries in an amount sufficient to fund the payment of the cash consideration at Closing.

Additionally, on February 6, 2015, the parties to the Merger Agreement entered into Amendment No. 1 to the Merger Agreement (the “Merger Agreement Amendment”). The Merger Agreement Amendment revises the descriptions of the tax opinions to be delivered by each of Nabors’ and C&J’s respective tax advisors in connection with the closing of the Merger. The tax opinion to be delivered to Nabors will be required to state that the distribution of Nabors Completion & Production Services Co. by Nabors International Finance Inc. to Nabors Blue Shield Ltd. is subject to the possible application of Section 355(d) of the Internal Revenue Code (the “Code”). The tax opinion to be delivered to C&J will be required to state that it is more likely than not that (i) the Merger qualifies as a reorganization within the meaning of Section 368(a) of the Code, and (ii) Red Lion qualifies as a corporation under Section 367(a) of the Code with respect to each transfer of property in connection with the Merger (with certain exceptions). Additionally, the Merger Agreement Amendment provides that if Nabors fails to deliver certain required financial information to C&J on or before the close of business on March 3, 2015, Nabors will not be entitled to recover a $65 million termination fee in the event C&J’s financing arrangements are not available to close the Merger. Finally, the Merger Agreement Amendment requires C&J to request each person treated as a “5-percent transferee shareholder” (as defined in the Treasury Regulations) enter into a “gain recognition agreement” (as defined in the Treasury Regulations) following the closing of the Merger.

Closing of the Pending Nabors Transaction is subject to customary closing conditions, including, among others, (1) the consummation of the Separation in accordance with the Separation Agreement; (2) the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (“HSR”), which termination occurred on July 28, 2014; (3) approval by C&J’s stockholders; (4) the registration statement on Form S-4 (the “S-4”) used to register

 

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the Red Lion common shares to be issued in the Merger, which includes a preliminary prospectus of Red Lion and a preliminary proxy statement of C&J, being declared effective by the SEC, which effectiveness was granted on February 13, 2015; (5) the approval for listing on the NYSE of the Red Lion common shares to be issued in the Merger; (6) subject to specified materiality standards, the accuracy of the representations and warranties of, and the performance of all covenants in the Merger Agreement, Separation Agreement and related closing documents by, the parties thereto; (7) the absence of a material adverse effect as defined in the Merger Agreement with respect to each of C&J and Red Lion; (8) the availability of the proceeds of the debt financing to effect the repayment of certain intercompany notes issued by subsidiaries of Red Lion to other subsidiaries of Nabors in connection with the Separation; (9) the receipt of consents, approvals and other deliverables with respect to certain agreements of C&J; (10) the receipt by Nabors of an opinion from its counsel to the effect that certain aspects of the Separation should qualify as tax-free pursuant to Section 355 of the Code; and (11) the receipt by C&J of an opinion from its counsel to the effect that it is more likely than not that (i) the Merger qualifies as a reorganization within the meaning of Section 368(a) of the Code and (ii) Red Lion qualifies as a corporation within the meaning of Section 367(a) of the Code.

On February 13, 2015, the S-4 was declared effective by the SEC, and we filed a definitive proxy statement dated February 13, 2015 with the SEC on that date. Mailing of the proxy statement, together with the Notice of Special Meeting and proxy card, to C&J stockholders of record on the record date commenced on February 13, 2015. The special meeting of C&J stockholders for purposes of approving the Pending Nabors Transaction and other matters detailed in the proxy statement will be held on March 20, 2015.

We currently expect the Closing to occur in March 2015, subject to approval of the Merger Agreement by C&J stockholders and other customary closing items. There can be no assurance as to whether or when the Closing will occur.

Strategic Initiatives and Growth Strategy

Expansion of Core Service Lines

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

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

With respect to our hydraulic fracturing operations, we deployed over 120,000 incremental hydraulic horsepower capacity during the year to take advantage of the rise in service-intensive completion activity that we experienced through most of 2014. Due to strategic planning and the flexibility and control provided by our in-house manufacturing capabilities, we were able to put these fleets to work with high activity operators immediately upon taking delivery of the equipment. We also grew our coiled tubing and wireline operations, deploying incremental equipment to strengthen our presence in highly active basins, and we gained market share in some of our newer operating regions. During the third quarter of 2014, we opened our first office in Wyoming, where we are now offering wireline services, as well as our directional drilling services, which we introduced to customers as a new service offering during the second quarter of 2014. Our directional drilling services line is described in

 

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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 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.

 

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Our key strategic initiatives in 2014 included the following:

 

    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.

 

    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.

 

    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.

 

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

 

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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

We currently operate 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 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

 

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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.

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.

 

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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.

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

 

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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.

Other Information About Our Business

Geographic Areas

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

Over the past several years, we have focused on expanding our geographic reach, both domestically and internationally. With respect to our international expansion efforts, during 2014 we continued to invest in the infrastructure needed to support the development of operations in the Middle East. In January 2014 we were awarded our first international contract to provide coiled tubing services on a trial basis in Saudi Arabia. During the first half of 2014, we established coiled tubing equipment, crews and logistics on the ground in Saudi Arabia to service this contract. We mobilized on location for our customer in late June 2014 and we successfully completed our first coiled tubing job in July 2014.

 

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

Seasonality

Our operations are subject to seasonal factors. Specifically, in the fourth quarter, we typically have experienced a pause by our customers around the holiday season, and activity will slow during the latter part of the year as our customers exhaust their annual capital spending budgets. Additionally, our operations are directly affected by weather conditions. During the winter months our customers may delay operations or we may not be able to operate or move our equipment between locations during periods of heavy snow, ice or rain. During the summer months, our operations may be impacted by tropical weather systems.

Sales and Marketing

Our sales and marketing activities relating to our core service lines are typically performed through our local operations in each geographic region. We believe our local field sales personnel have an excellent understanding of region-specific issues and customer operating procedures and, therefore, can effectively target marketing activities. We also have multiple corporate sales representatives that supplement our field sales efforts and focus on large accounts and selling technical services. Our sales representatives work closely with our local managers and field sales personnel to target compelling market opportunities. We facilitate teamwork among our sales representatives by basing a portion of their compensation on aggregate company sales targets rather than individual sales targets. We believe this emphasis on teamwork enables us to better serve our existing customers and will also allow us to further expand our customer base.

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

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

 

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Customers

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

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

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

Our top ten customers accounted for approximately 51.1%, 64.6% and 81.0% of our consolidated revenue for the years ended December 31, 2014, 2013 and 2012, respectively. For the year ended December 31, 2014, revenue from Anadarko Petroleum Corporation and Apache Corporation represented 16.4% and 9.6%, respectively, of our consolidated revenue. For the year ended December 31, 2013, revenue from Anadarko Petroleum Corporation and Apache Corporation individually represented 19.5% and 13.1% respectively, of our consolidated revenue. For the year ended December 31, 2012, revenue from Anadarko Petroleum Corporation, Apache Corporation, and Freeport-McMoRan Oil and Gas individually represented 19.1%, 15.6%, 12.9%, respectively, of our consolidated revenue. Other than those listed above, no other customer accounted for more than 10% of our consolidated revenue in 2014, 2013 or 2012. If we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. We monitor closely the financial condition of our customers, their capital expenditure plans, and other indications of their drilling and completion activities.

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

Industry Overview; Competition and Demand for Our Services

The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling, completion and workover budget. The oil and gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity, weather

 

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conditions, and other factors that are beyond our control. The volatility of the oil and gas industry, and the consequent negative impact on the level of exploration, development and production activity and capital expenditures by our customers, has adversely affected, and in the future may adversely affect, the demand for our services. This, in turn, negatively impacts our ability to maintain utilization of assets and negotiate pricing at levels generating sufficient margins, especially in our hydraulic fracturing business.

Demand for our services tends to be extremely volatile and cyclical, as it is a direct function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the United States. Our customers’ willingness to undertake such activities and expenditures depends largely upon prevailing industry conditions that are influenced by numerous factors which are beyond our control, including, among other things, current and expected future levels of oil and natural gas prices and the perceived stability and sustainability of those prices, which, in turn, is driven primarily by the supply of, and demand for, oil and natural gas. Oil and natural gas prices, and therefore the level of drilling, completion and workover activity by our customers, historically have been extremely volatile and are expected to continue to be highly volatile. For example, within the past year, oil prices were as high as $107 per barrel and have been as low as $44 per barrel. Generally, as the supply of these commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural gas price environment, demand for service and maintenance generally decreases as oil and natural gas producers decrease their activity and expenditures. In particular, the demand for drilling, completion and workover services is driven by available investment capital for such activities. When these capital investments decline, our customers’ demand for our services declines. Because the type of services that we offer can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we typically experience a more rapid decline in demand for our services compared with demand for other types of energy services. A prolonged low level of customer activity will adversely affect the demand for our services and our financial condition and results of operations.

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

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

 

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not be able to reduce our costs accordingly, which could further adversely affect our results. Furthermore, even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset any rising costs. Also, we may not be able to successfully increase prices without adversely affecting our utilization levels. The inability to maintain our utilization and pricing levels, or to increase our prices as costs increase, could have a material adverse effect on our business, financial position and results of operations.

Our competitors include many large and small energy service companies, including some of the largest integrated energy services companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can, including by reducing prices for services. Our major competitors for our hydraulic fracturing services include Halliburton, Schlumberger, Baker Hughes, Calfrac Well Services, Trican, Weatherford International, RPC, Inc., Pumpco, an affiliate of Superior Energy Services, and Frac Tech. Our major competitors for our coiled tubing and other well stimulation services include Halliburton, Schlumberger, Baker Hughes, RPC, Inc. and a significant number of regional businesses. Our major competitors for our wireline services include Schlumberger, Halliburton and Archer.

We believe that the principal competitive factors in the markets that we serve are technical expertise, equipment capacity, work force capability, safety record, reputation and experience. Although we believe our customers consider all of these factors, price is often the primary factor in determining which service provider is awarded work. Additionally, projects are often awarded on a bid basis, which tends to further increase competition based primarily on price. While we must be competitive in our pricing, we believe many of our customers elect to work with us based on the safety, performance and quality of our crews, equipment and services. We seek to differentiate ourselves from our major competitors by our operating philosophy, which is focused on delivering the highest quality customer service and equipment, coupled with superior execution and operating efficiency. As part of this strategy, we target high volume, high efficiency customers with service intensive, 24-hour work, which is where we believe we can differentiate our services from our competitors.

See Part II, Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations - Industry Trends and Outlook” for additional discussion of the market challenges within our industry.

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

Suppliers

We purchase raw materials (such as proppant, guar, fracturing fluids or coiled tubing) and finished products (such as fluid-handling equipment) used in our Stimulation and Well Intervention Services and Wireline Services segments from various third-party suppliers, as well as from our equipment manufacturing and specialty chemicals businesses. During the year ended December 31, 2014, only our equipment manufacturing business and our specialty chemicals business supplied 5% or more of the materials and/or products used in our Stimulation and Well Intervention Services and Wireline Services segments. We are not dependent on any single supply source for these materials or products and we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers. However, should we be unable to purchase the necessary materials and/or products, or otherwise be unable to procure the materials and/or products in a timely manner and in the quantities required, we may be delayed in providing our services, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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

Safety

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

Our record and reputation for safety is important to all aspects of our business. In the energy services industry, an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. In recent years, many of our larger customers have placed an added emphasis on the safety records and quality management systems of their contractors. We believe that these factors will gain further importance in the future.

Risk Management and Insurance

Our operations in our Stimulation and Well Intervention Services and Wireline Services segments are subject to hazards inherent in the oil and gas industry, including accidents, blowouts, explosions, craterings, fires, oil spills and hazardous materials spills. These conditions can cause:

 

    personal injury or loss of life;

 

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

 

    suspension of operations.

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

 

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

Despite our efforts to maintain high safety standards, we from time to time have suffered accidents, and it is likely that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, and our relationship with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

We maintain general liability insurance coverage of types and amounts that we believe to be customary in the industry, including sudden and accidental pollution insurance. Our sudden and accidental pollution insurance coverage is currently included under general liability, consisting of $1.0 million of underlying coverage for each occurrence, $10.0 million of umbrella coverage for each occurrence and $90.0 million of additional excess coverage for each occurrence. We also maintain insurance for property damage relating to catastrophic events. As discussed below, our Master Service Agreements (“MSAs”) with each of our customers provide, among other things, that our customers generally assume (without regard to fault) liability for underground pollution and pollution emanating from the wellbore as a result of an explosion, fire or blowout. We retain the risk for any liability not indemnified by our customers in excess of our insurance coverage. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements.

We enter into MSAs with each of our customers. Our MSAs delineate our and our customer’s respective indemnification obligations with respect to the services we provide. With respect to our Stimulation and Well Intervention Services and Wireline Services, our MSAs typically provide for knock-for-knock indemnification for all losses, which means that we and our customers assume liability for damages to or caused by our respective personnel and property. For catastrophic losses, our MSAs generally include industry-standard carve-outs from the knock-for-knock indemnities, pursuant to which our customers (typically the exploration and production company) assume liability for (i) damage to the hole, including the cost to re-drill; (ii) damage to the formation, underground strata and the reservoir; (iii) damages or claims arising from loss of control of a well or a blowout; and (iv) allegations of subsurface trespass. Additionally, our MSAs typically provide that we can be held responsible for events of catastrophic loss only if they arise as a result of our gross negligence or willful misconduct.

Our MSAs typically provide for industry-standard pollution indemnities, pursuant to which we assume liability for surface pollution associated with our equipment and resulting from our negligent actions, and our customer assumes (without regard to fault) liability arising from all other pollution, including, without limitation, underground pollution and pollution emanating from the wellbore as a result of an explosion, fire or blowout.

The description of insurance policies set forth above is a summary of the material terms of our insurance policies currently in effect and may change in the future as a result of market and/or other conditions. Similarly, the summary of MSAs set forth above is a summary of the material terms of the typical MSA that we have in place and does not reflect every MSA that we have entered into or may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different than those described here.

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

 

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Employees

As of February 13, 2015, we had 3,490 employees. We increased our overall headcount by approximately 40% over the course of 2014 to support the growth of our business. Subject to local market conditions, the additional crew members needed for our Stimulation and Well Intervention Services and Wireline Services are generally available for hire on relatively short notice. Our employees are not represented by any labor unions or covered by collective bargaining agreements. We consider our relations with our employees to be generally good.

Government Regulations

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

Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the United States Department of Transportation (“DOT”) and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period and requiring onboard black box recorder devices or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by DOT. To a large degree, intrastate motor carrier operations are subject to safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers.

From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

In addition, some of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the United States Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. We believe that we have obtained these licenses and approvals when necessary and that we are in substantial compliance with these requirements.

 

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Environmental Matters

Our operations are subject to stringent and complex federal, state and local environmental and occupational, health and safety laws and regulations, including those governing the release and/or discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, injunctions prohibiting some or all of our operations, assessment of administrative and civil penalties, and even criminal prosecution. We believe that we are in substantial compliance with applicable environmental laws and regulations. Further, we do not anticipate that compliance with existing environmental laws and regulations will have a material effect on our financial condition or results of operations. It is possible, however, that substantial costs for compliance or penalties for non-compliance may be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations, and enforcement policies, could result in additional costs or liabilities that we cannot currently quantify.

Hazardous Substances

We generate wastes, including hazardous wastes, which are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”), the NRC, and state agencies have limited the approved methods of disposal for some types of hazardous and nonhazardous wastes. RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.” Disposal of such non-hazardous oil and natural gas exploration, development and production wastes is usually regulated by state law. Other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,” thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted. Additionally, Naturally Occurring Radioactive Materials (“NORM”) may contaminate extraction and processing equipment used in the oil and natural gas industry. The waste resulting from such contamination is regulated by federal and state laws. Standards have been developed for: worker protection; treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. It is possible that we may incur costs or liabilities associated with elevated levels of NORM.

The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or the “Superfund” law), and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Under CERCLA, these persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and natural gas related operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties

 

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and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging of disposal wells or waste pit closure operations to prevent future contamination. These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed.

Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”), and comparable state statutes impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. Also, spill prevention, control and countermeasure regulations under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.

In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Moreover, the Oil Pollution Act of 1990 (“OPA”) imposes a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages, including natural resource damages, resulting from such spills in waters of the United States. A responsible party includes the owner or operator of an onshore facility. The Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the OPA, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.

The Safe Water Drinking Act (“SDWA”), regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, the EPA recently has taken the position that hydraulic fracturing with fluids containing diesel fuel are subject to regulation under the UIC program, specifically as “Class II” UIC wells. We do not utilize diesel fuel in our fracturing services. In addition, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to perform services may be delayed or limited, which could have an adverse effect on our results of operations and financial position.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly perform hydraulic fracturing services for our customers. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but, as noted above, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance in February 2014 that applies to such activities. Also, in May 2014, the EPA published an advanced notice of proposed rulemaking under the Toxic Substances and Control Act that would require the disclosure of chemicals used in hydraulic fracturing fluids. In addition, from time to time legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.

 

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The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA is performing a study of the potential environmental effects of hydraulic fracturing on drinking water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report sometime in 2015. The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards sometime in 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. Depending on their results, these studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business.

There have been no material incidents or citations related to our hydraulic fracturing operations in the past five years. During that period we have not been involved in any litigation over alleged environmental violations, have not been ordered to pay any material monetary fine or penalty with respect to alleged environmental violations, and are not currently facing any type of governmental enforcement action or other regulatory proceeding involving alleged environmental violations related to our hydraulic fracturing operations. In addition, pursuant to our MSAs, we are generally liable for only surface pollution, not underground or flowback pollution, which our customers are generally liable for and for which we are typically indemnified by our customers.

We maintain insurance against some risks associated with underground contamination that may occur as a result of well services activities. However, this insurance is limited to activities at the well site and may not continue to be available or may not be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a materially adverse effect on our financial condition and results of operations.

Air Emissions

Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act (“CAA”), and analogous state laws require permits for certain facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose generally applicable limitations on air emissions and require adherence to maintenance, work practice, reporting and recordkeeping, and other requirements. Many of

 

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these regulatory requirements, including New Source Performance Standards (“NSPS”) and Maximum Achievable Control Technology (“MACT”) standards are expected to be made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of substantial administrative, civil and even criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional expenses and operational delays.

In addition, oil and natural gas production, processing, transmission and storage operations are now subject to regulation under the New Source Performance Standards and National Standards for Emission of Hazardous Air Pollutants programs. These rules require, among other things, the reduction of volatile organic compound (“VOC”) emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” wells must use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. The rule is designed to limit emissions of VOC, sulfur dioxide, and hazardous air pollutants from a variety of sources within natural gas processing plants, oil and natural gas production facilities, and natural gas transmission compressor stations. This rule could require a number of modifications to oil and gas exploration and production operations, including the installation of new equipment. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase costs for us and our customers. Although we do not believe our operations will be materially adversely affected by these requirements, our business could be materially affected if our customers’ operations are significantly affected by these or other similar requirements. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and gas our customers produce, and thus have an adverse effect on the demand for our products and services.

Climate Change

More stringent laws and regulations relating to climate change may be adopted in the future and could cause us to incur additional operating costs or reduce the demand for our services. The EPA has determined that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations that restrict emissions of GHGs under existing provisions of the CAA, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain preconstruction and operating permit reviews for GHG emissions from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG sources, including, among others, certain oil and natural gas production facilities, on an annual basis. We do not believe our operations are currently subject to these requirements, but our business could be affected if our customers’ operations become subject to these or other similar requirements. Moreover, these requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and gas our customers produce, and thus have a material adverse effect on the demand for our products and services.

In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, to acquire and surrender emission allowances. The number of allowances available for

 

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purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any new federal, regional or state restrictions on emissions of carbon dioxide or other GHGs that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such restrictions could potentially make our customers’ products more expensive and thus reduce demand for such products, which in turn could have a material adverse effect on the demand for our services and our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

Worker Safety

We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

 

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Item 1A. Risk Factors

We face many challenges and risks in the industry in which we operate. Before investing in our shares you should carefully consider each of the following risk factors and all of the other information set forth in this Form 10-K including under the section titled “Cautionary Note Regarding Forward-Looking Statements”) and our other reports filed with the SEC, and the documents and other information incorporated by reference herein and therein, for a detailed discussion of known material factors which could materially affect our business, financial condition or future results. The risks and uncertainties described are not the only ones we face. Additional risk factors not presently known to us or which we currently consider immaterial may also adversely affect our business, financial condition or future results. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our shares could decline and you could lose all or part of your investment.

Risks Relating to Our Business

Our business is cyclical and dependent upon conditions in the oil and natural gas industry, which impact the level of exploration, development and production of oil and natural gas and capital expenditures by oil and natural gas companies. Our customers’ willingness to undertake exploration and production activities depends largely upon prevailing industry conditions that are influenced by numerous factors which are beyond our control. Any of these factors could have a material adverse effect on our business, financial condition, results of operations and cash flow.

We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas. If these expenditures decline, our business may suffer. The oil and gas industry has traditionally been volatile, is highly sensitive to supply and demand cycles and is influenced by a combination of long-term, short-term and cyclical trends. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as:

 

    the supply of and demand for oil and natural gas, including current natural gas storage capacity and usage;

 

    the ability or willingness of the Organization of Petroleum Exporting Countries to set and maintain production levels for oil;

 

    the current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices;

 

    the supply of and demand for hydraulic fracturing and other well service equipment in the United States;

 

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

 

    public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;

 

    the expected rates of decline of current oil and natural gas production;

 

    lead times associated with acquiring equipment and products and availability of personnel;

 

    regulation of drilling activity;

 

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    the discovery and development rates of new oil and natural gas reserves;

 

    available pipeline and other transportation capacity;

 

    weather conditions, including hurricanes that can affect oil and natural gas operations over a wide area;

 

    political instability in oil and natural gas producing countries;

 

    domestic and worldwide economic conditions;

 

    technical advances affecting energy consumption;

 

    the price and availability of alternative fuels; and

 

    merger and divestiture activity among oil and natural gas producers.

Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) generally leads to decreased spending by our customers, which in turn negatively impacts exploration, development and production activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work. When these capital investments decline, our customers’ demand for our services declines. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we typically experience a more rapid decline in demand for our services compared with demand for other types of energy services. While higher oil and natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Any negative impact on the spending patterns of our customers may cause lower pricing and utilization for our core service lines, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Spending by exploration and production companies can also be impacted by conditions in the capital markets. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause exploration and production companies to make additional reductions to capital budgets in the future even if oil prices remain at current levels or natural gas prices increase from current levels. Any such cuts in spending may curtail drilling programs as well as discretionary spending on well services, which may result in a reduction in the demand for our services, and the rates we can charge and the utilization of our assets. Moreover, reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves, in our market areas, whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, could also have a material adverse impact on our business, even in a stronger oil and natural gas price environment.

Fluctuations in oil and natural gas prices could adversely affect drilling, completion and production activities by oil and natural gas companies and our revenues, cash flows and profitability. If oil and natural gas prices remain volatile, or if oil or natural gas prices remain low or decline further, the demand for our services could be adversely affected.

The demand for our services depends on the level of spending by oil and gas companies for drilling, completion and production activities, which are affected by short-term and long-term trends in oil and natural gas prices, including current and anticipated oil and natural gas prices. Oil and natural gas prices, as well as the level of drilling, completion and production activities, historically have been extremely volatile and are expected to continue to be highly volatile. For example, within the past year, oil prices were as high as $107 per barrel and have been as low as $44 per barrel. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting

 

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Countries, affect both the demand for, and the supply of, oil and natural gas. Weather conditions, governmental regulation (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity and other factors that will be beyond our control may also affect the supply of, demand for, and price of oil and natural gas. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower completion and production spending on existing wells. This, in turn, could result in lower demand for our services and cause lower pricing and utilization levels for our services. If oil prices decline or natural gas prices continue to remain low or decline further, or if there is a reduction in drilling and completion activities, the demand for our services and our results of operations could be materially and adversely affected.

The oilfield services industry is very competitive with significant excess capacity in our industry, which could adversely affect our business and operating results.

The oilfield services industry is very competitive. Significant increases in overall market capacity have caused active price competition and lead to lower pricing and utilization levels for our services. Completion and well servicing equipment, such as hydraulic fracturing fleets, can be moved from one region to another in response to changes in levels of activity and market conditions, which may result in an oversupply of equipment in an area. For example, natural gas prices declined sharply in 2009 and remained depressed through 2014, which resulted in reduced drilling activity in natural gas shale plays. This drove many energy services companies operating in those areas to relocate their equipment to more oily- and liquids-rich shale plays, such as the Eagle Ford Shale and Permian Basin. As drilling activity and completion capacity migrated into the oily- and liquids-rich regions from the gas-rich regions, the increase in supply relative to demand negatively impacted pricing and utilization of our services, particularly for hydraulic fracturing services. Additionally, the recent decline in oil prices has further reduced demand for our services. Any significant future increase in overall market capacity completion services could adversely affect our business and results of operations.

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

The majority of our revenue is generated from our hydraulic fracturing services, which we provide on a spot market basis. With the expiration of all of our legacy term “take-or-pay” contracts, which had minimum utilization requirements and favorable pricing terms relative to the current spot market pricing, we are now subject to substantial market exposure.

Pressure on pricing for our hydraulic fracturing and other core services, including due to competition and industry and/or economic conditions, may impact, among other things, our ability to implement price increases or maintain pricing on our core services. We operate in a very competitive industry and, as a result, we may not always be successful in raising, or maintaining our existing prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including hydraulic fracturing equipment and coiled tubing units, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase or maintain prices. Furthermore, during periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our profitability.

Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset such rising costs. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our prices or to increase our prices as costs increase could have a material adverse effect on our business, financial position and results of operations.

 

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

The majority of our revenue is generated from our hydraulic fracturing services. Due to the large percentage of our revenue historically derived from our hydraulic fracturing services pursuant to our term contracts and the limited size of our fracturing fleets, our customer concentration has historically been high. Our top ten customers represented approximately 51.1%, 64.6% and 81.0% of our consolidated revenue for the years ended December 31, 2014, 2013 and 2012, respectively. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.

Delays in deliveries of key raw materials or increases in the cost of key raw materials could harm our business, results of operations and financial condition.

We have established relationships with a limited number of suppliers of our raw materials (such as proppant, guar, chemicals or coiled tubing) and finished products (such as fluid-handling equipment). Should any of our current suppliers be unable to provide the necessary raw materials or finished products or otherwise fail to deliver the products in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, increasing costs of certain raw materials, including guar, may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic proppant shortages associated with hydraulic fracturing operations requiring work stoppages, which adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of raw materials, including proppants.

Weather conditions could materially impair our business.

Our operations may be adversely affected by severe weather events and natural disasters. Furthermore, our customers’ operations may be adversely affected by seasonal weather conditions. For example, hurricanes, tropical storms, heavy snow, ice or rain may result in customer delays and other disruptions to our services. Repercussions of severe weather conditions may include:

 

    curtailment of services;

 

    weather-related damage to facilities and equipment, resulting in suspension of operations;

 

    inability to deliver equipment, personnel and products to job sites in accordance with contract schedules;

 

    increase in the price of insurance; and

 

    loss of productivity.

These constraints could also delay our operations, reduce our revenue and materially increase our operating and capital costs.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect demand for our support services.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly perform hydraulic fracturing services for our customers.

 

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Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance in February 2014 that applies to such activities. Also, in May 2014, the EPA published an advanced notice of proposed rulemaking under the Toxic Substances and Control Act that would require the disclosure of chemicals used in hydraulic fracturing fluids. In addition, from time to time legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.

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

In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction, and temporary or permanent bans on hydraulic fracturing in certain areas. For example, in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business.

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, increase our costs of compliance and adversely affect the hydraulic fracturing services that we render for our exploration and production customers. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

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

Our future success depends upon the continued service of our executive officers and other key personnel, particularly Joshua E. Comstock, our founder, Chief Executive Officer and Chairman of the Board of Directors. If we lose the services of Mr. Comstock, or that of our other executive officers or key

 

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personnel, our business, operating results and financial condition could be harmed. Additionally, although we maintain key person life insurance on Mr. Comstock, the proceeds from such insurance would not be sufficient to cover our losses in the event we were to lose his services.

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

We have grown rapidly over the last several years. For example, from the year ended December 31, 2008, through the year ended December 31, 2014, our net income increased from $1.1 million to $68.8 million and our revenue increased from $62.4 million to $1.6 billion. We believe that our future success depends on our ability to continue to manage the rapid organic growth that we have experienced and expect to continue to experience, as well as the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:

 

    lack of sufficient executive-level personnel;

 

    increased administrative burden;

 

    long lead times associated with acquiring additional equipment; and

 

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

In addition, in the future we may seek to grow our business through acquisitions that enhance our existing operations. The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our operating results could be adversely affected if we do not successfully manage these potential difficulties in integrating the businesses we may acquire.

We may be unable to employ a sufficient number of skilled and qualified workers.

The delivery of our services and products requires personnel with specialized skills and experience who can perform physically demanding work. As a result of the volatility in the energy service industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a different work environment. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. At times, demand for skilled workers in our geographic area of operations is high, and the supply is limited. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Our operations are subject to hazards inherent in the energy services industry.

Risks inherent to our industry, such as equipment defects, vehicle accidents, explosions and uncontrollable flows of gas or well fluids, can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruption and damage to, or destruction of property, equipment and the environment. In addition, our hydraulic fracturing and well completion services could become a source of spills or releases of fluids, including chemicals used during hydraulic fracturing activities, at the site where such services are performed, or could result in the discharge of such fluids into underground formations that were not targeted for fracturing or well completion activities, such as potable aquifers. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental

 

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damages and could result in a variety of claims, losses and remedial obligations that could have an adverse effect on our business and results of operations. The existence, frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable, which could cause us to lose customers and substantial revenue.

Our operational personnel have experienced accidents which have, in some instances, resulted in serious injuries. Our safety procedures may not always prevent such damages. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations and cash flows.

We participate in a capital-intensive industry, and we may not be able to finance future growth of our operations or future acquisitions.

Since the beginning of 2011, our growth has been funded by cash flows from operations, borrowings under our credit facilities and the net proceeds we received from our initial public offering (“IPO”), which closed on August 3, 2011. 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. Upon consummation of the Pending Nabors Transaction, we expect to have approximately $1.1 billion in total indebtedness, and $520 million available for additional borrowings. Our current indebtedness, or, following closing of the Pending Nabors Transaction, the substantial indebtedness that will be incurred in connection with the Pending Nabors Transaction, 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.

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. Although we believe we are well positioned to finance our future growth, if we are unable to generate sufficient cash flows or to obtain additional capital on favorable terms or at all, we may be unable continue growing our business or to sustain or increase our current level profitability. Our inability to grow our business may adversely impact our ability to sustain or improve our profits.

Our industry is highly competitive and we may not be able to provide services that meet the specific needs of oil and natural gas exploration and production companies at competitive prices.

Our industry is highly competitive. The principal competitive factors in our markets are generally technical expertise, fleet capability and experience. We compete with large national and multi-national companies that have longer operating histories, greater financial resources and greater name recognition than we do and who can operate at a loss in the regions in which we operate. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, there are several smaller companies capable of competing effectively on a regional or local basis, with numerous start-ups emerging in recent years. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our

 

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business, financial condition, results of operations and cash flows. In addition, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality. Our reputation for safety and quality may not be sufficient to enable us to maintain our competitive position.

Covenants in our debt agreement restrict our business in many ways.

Our $500.0 million senior secured revolving credit facility, dated as of April 19, 2011 (the “Credit Facility”), contains restrictive covenants and requires us to maintain a certain debt coverage ratio, to maintain a certain fixed charge coverage ratio and to satisfy other financial condition tests. Our ability to meet those financial requirements may be affected by adverse industry conditions and other events beyond our control, and we cannot be certain that we will meet those requirements. In addition, our Credit Facility contains a number of additional restrictive covenants, including a covenant limiting, subject to certain exceptions, our ability to make capital expenditures in excess of the greater of (x) 12.5% of the consolidated tangible assets of us and our subsidiaries and (y) $200.0 million in any fiscal year, 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 of such amount may also be pulled forward from the subsequent fiscal year. However, we are allowed to make an unlimited amount of capital expenditures so long as (i) our 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. In addition, the capital expenditure restrictions do not apply to capital expenditures financed with proceeds from the issuance of common equity interests or to capital expenditures made to extend the useful life of existing equipment.

At closing of the Pending Nabors Transaction, it is expected that our combined company will obtain (i) senior secured credit facilities (the “New C&J Senior Secured Credit Facilities”) consisting of (a) a revolving credit facility (the “Revolving Credit Facility”) in an aggregate principal amount of $520 million and (b) a term loan B facility in an aggregate principal amount of $585 million, and (ii) senior unsecured bridge loans in an aggregate principal amount of $520 million. Upon consummation of the Pending Nabors Transaction, we expect to have approximately $1.1 billion in total indebtedness, and $520 million available for additional borrowings. The Senior Secured Credit Agreement 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.

Our ability to meet our expense and debt service obligations contained in the agreements governing our indebtedness will depend on our future performance, which will be affected by many factors outside of our control, including financial, business, economic and other factors, such as potential changes in customer preferences and pressure from competitors. Should our revenues decline, we may not be able to generate sufficient cash flow to pay our debt service obligations when due. If we are unable to meet our debt service obligations or should we fail to comply with the financial and other restrictive covenants under the C&J Credit Facility or the New C&J Senior Secured Credit Facilities (as applicable), we may be required to refinance all or part of our debt, sell important strategic assets at unfavorable prices or borrow more money. We may not be able to, at any given time, refinance our debt, sell assets or borrow more money on acceptable terms acceptable or at all. Our inability to refinance our outstanding debt or access the capital markets could cause us to breach the financial and other restrictive covenants under the C&J Credit Facility or the New C&J Senior Secured Credit Facilities (as applicable), and also could have a material adverse effect on our financial condition and results from operations.

A breach of any of the covenants under the C&J Credit Facility or the New C&J Senior Secured Credit Facilities (as applicable) could result in a default under such agreement. Upon the occurrence of an event of default under the C&J Credit Facility or the New C&J Senior Secured Credit Facilities (as

 

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applicable), the lenders could elect to declare all amounts outstanding to be immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under the C&J Credit Facility or the New C&J Senior Secured Credit Facilities (as applicable) could proceed against the collateral granted to them to secure that indebtedness.

We have pledged a significant portion of our and our subsidiaries’ assets as collateral under the C&J Credit Facility and it is expected that we will pledge a significant portion of our combined companies’ assets as collateral under the New C&J Senior Secured Credit Facilities, If the lenders under our Credit Facility or the New C&J Senior Secured Credit Facilities (as applicable) accelerate the repayment of borrowings, we may not have sufficient assets to repay indebtedness under such facilities and our other indebtedness. See “Note 2 – Long-Term Debt and Capital Lease Obligations” in Part II, Item 8 “Financial Statements and Supplementary Data.”

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for our services.

The EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the federal CCA Act including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain preconstruction and operating permit reviews for GHG emissions from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of GHGs from specified GHG emission sources, including, among others, certain oil and natural gas production facilities, on an annual basis. In addition to the EPA, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. The Obama Administration has also announced that it intends to release a series of new regulations on the oil and gas industry in 2015, including federal standards limiting methane emissions.

Any new federal, regional or state restrictions on emissions of GHGs that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such legislation could also potentially make our customers’ products more expensive and thus reduce demand for those products, which could have a material adverse effect on the demand for our services and our business. Finally, some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our results of operations.

We are subject to extensive and costly environmental, and occupational health and safety laws, and regulations that may require us to take actions that will adversely affect our results of operations.

Our business is significantly affected by stringent and complex federal, state and local laws and regulations governing the emission or discharge of substances into the environment, protection of the environment and worker health and safety. Any failure by us to comply with such environmental and occupational health and safety laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the following:

 

    issuance of administrative, civil and criminal penalties;

 

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    modification, denial or revocation of permits or other authorizations;

 

    imposition of limitations on our operations; and

 

    performance of site investigatory, remedial or other corrective actions.

As part of our business, we handle, transport, and dispose of a variety of fluids and substances used by our customers in connection with their oil and natural gas exploration and production activities. We also generate and dispose of nonhazardous and hazardous wastes. The generation, handling, transportation, and disposal of these fluids, substances, and wastes are regulated by a number of laws, including CERCLA, RCRA, Clean Water Act, SDWA and analogous state laws. Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to liability for governmental penalties, third-party claims, cleanup costs associated with releases of such materials, damages to natural resources, and other damages, as well as potentially impair our ability to conduct our operations. Moreover, certain of these environmental laws impose joint and several, strict liability even though our conduct in performing such activities was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties was the basis for such liability. In addition, environmental laws and regulations are subject to frequent change and if existing laws, regulatory requirements or enforcement policies were to change in the future, we may be required to make significant unanticipated capital and operating expenditures.

More stringent trucking regulations may increase our costs and negatively impact our results of operations.

As part of the services we provide, we operate as a motor carrier and therefore are subject to regulation by the DOT, and by other various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. In addition, the trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, require onboard black box recorder devices or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by the DOT. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.

From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

New technology may hurt our competitive position.

The energy service industry is subject to the introduction of new completion techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to

 

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implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations.

We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar foreign anti-bribery laws.

The United States Foreign Corrupt Practices Act (the “FCPA”) and similar worldwide anti-bribery laws generally prohibit companies and their intermediaries from making, offering or authorizing improper payments to non-U.S. government officials for the purpose of obtaining or retaining business. We do business and may do additional business in the future in countries or regions where strict compliance with anti-bribery laws may conflict with local customs and practices. Violations of anti-bribery laws (either due to our acts or our inadvertence) may result in criminal and civil sanctions and could subject us to other liabilities in the U.S. and elsewhere. Even allegations of such violations could disrupt our business and result in a material adverse effect on our business and operations.

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

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

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

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

 

    expropriation, confiscation or nationalization of assets;

 

    renegotiation or nullification of existing contracts;

 

    foreign exchange limitations;

 

    foreign currency fluctuations;

 

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    foreign taxation;

 

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

 

    changing political conditions;

 

    changing foreign and domestic monetary policies;

 

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

 

    regional economic downturns.

Risks Related to the Pending Nabors Transaction

We cannot assure you that we will complete the Pending Nabors Transaction or, if completed, that such transaction will be beneficial to us.

We cannot assure you that we will complete the Pending Nabors Transaction or, if completed, that such transaction would achieve the desired benefits. The success of the Pending Nabors Transaction will depend, in part, on the ability of the combined company to realize the anticipated benefits from combining our business with the C&P Business. Realizing the benefits of the Pending Nabors Transaction will depend in part on the integration of assets, operations and personnel while maintaining adequate focus on the core businesses of the combined company. We cannot assure you that any cost savings, greater economies of scale and other operational efficiencies, as well as revenue enhancement opportunities anticipated from the business combination will occur. If management of the combined company is unable to minimize the potential disruption of the combined company’s ongoing business and distraction of the management during the integration process, the anticipated benefits of the Pending Nabors Transaction may not be realized. These integration matters could have an adverse effect on us.

If we consummate the Pending Nabors Transaction and if any of these risks or unanticipated liabilities or costs were to materialize, any desired benefits of the Pending Nabors Transaction may not be fully realized, if at all, and our future financial performance and results of operations could be negatively impacted. Further, the failure to complete the Pending Nabors Transaction could negatively impact the market price of our shares of common stock and our future business and financial results, and we may experience negative reactions from the financial markets and from our customers and employees.

We will continue to incur substantial transaction-related costs in connection with the Pending Nabors Transaction.

We have incurred significant transaction, integration and transition costs associated with the Pending Nabors Transaction and we expect to continue to incur significant costs associated with completing the Pending Nabors Transaction, combining the operations of the C&P Business with our business and achieving desired synergies. These fees and costs will be substantial. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time. Thus, any net benefit may not be achieved in the near term, or at all.

Pending the completion of the Pending Nabors Transaction, our business and operations could be materially adversely affected.

Under the terms of the Merger Agreement, we are subject to certain restrictions on the conduct of our business prior to completing the Pending Nabors Transaction which may adversely affect our ability to execute certain of our business strategies, including our ability in certain cases to enter into contracts or

 

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incur capital expenditures to grow our business. Such limitations could negatively affect our business and operations prior to the completion of the Merger. Additionally, uncertainty about the effect of the Pending Nabors Transaction on employees, customers and suppliers may have an adverse effect on our business. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is consummated and for a period of time thereafter, and could cause our customers, suppliers and others who deal with us to seek to change their existing business relationships, which could negatively impact revenues, earnings and cash flows of our business, as well as the market prices of our common stock, regardless of whether the Merger is completed. Furthermore, matters relating to the Pending Nabors Transaction may require substantial commitments of time and resources by management, which could otherwise have been devoted to other opportunities that may have been beneficial to us.

The Pending Nabors Transaction is subject to conditions, including certain conditions that may not be satisfied on a timely basis, if at all.

The completion of the Pending Nabors Transaction is subject to a number of conditions, including the approval of the Merger by C&J stockholders, which makes the completion and timing of the closing of the Pending Nabors Transaction uncertain. We cannot predict whether and when these conditions will be satisfied. Any delay in completing the Pending Nabors Transaction could cause the combined company not to realize all or some of the synergies that we expect to achieve if the Pending Nabors Transaction is successfully completed within its expected timeframe.

Failure to complete the Pending Nabors Transaction could negatively affect our share price and our future business and financial results.

We cannot make any assurances that they will be able to satisfy all of the conditions to the Pending Nabors Transaction or succeed in any litigation brought in connection with the Pending Nabors Transaction. If the Pending Nabors Transaction is not completed, or if there are significant delays in completing the Pending Nabors Transaction, our financial results may be adversely affected and we will be subject to several risks, including:

 

    our business may have been adversely affected by the failure to pursue other beneficial opportunities due to the focus of management on the Pending Nabors Transaction and certain restrictions under the Merger Agreement, without realizing any of the anticipated benefits of completing the Pending Nabors Transaction;

 

    we will have paid certain costs relating to the Pending Nabors Transaction, such as legal, accounting, financial advisor and printing fees, without realizing any of the anticipated benefits of completing the Pending Nabors Transaction;

 

    the market price of our common stock might decline to the extent that the current market price reflects a market assumption that the Pending Nabors Transaction will be completed;

 

    we may experience negative reactions from the financial markets and from its customers and employees and/or could be subject to litigation related to a failure to complete the Pending Nabors Transaction;

 

    if the Merger Agreement is terminated under certain circumstances, we may be required to pay a termination fee of up to $65 million to Nabors;

 

    if our board of directors seeks out another business combination following termination of the Merger Agreement, our stockholders cannot be certain that we will be able to find a party willing to enter into a more or equally favorable arrangement than the terms provided for in the Merger Agreement; and

 

    we may become subject to litigation related to any failure to complete the Pending Nabors Transaction.

 

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If the Pending Nabors Transaction is not completed, we cannot assure our stockholders that these risks will not materialize and will not materially and adversely affect our business, financial results and stock price.

The integration of C&J with the C&P Business following the Pending Nabors Transaction may present challenges and cannot be assured.

There are difficulties inherent in the process of integrating C&J with the C&P Business. These difficulties include, but are not limited to, the following:

 

    the integration of C&J with the C&P Business while carrying on the ongoing operations of each business;

 

    the challenge and cost of integrating the information technology systems of each of C&J and the C&P Business, which presently are run under different operating software systems;

 

    the challenge of integrating the business cultures of each of C&J and the C&P Business; and

 

    the potential difficulty in retaining key officers and personnel of C&J and the C&P Business.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of one or more of our businesses. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business, service existing customers, attract new customers and develop new products or strategies. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

Our successful or cost-effective integration of C&J with the C&P Business cannot be assured. The failure to do so could have a material adverse effect on our business, financial condition and results of operations after the consummation of the Pending Nabors Transaction.

The pendency of the Pending Nabors Transaction could materially adversely affect the business and operations of C&J and the C&P Business or result in a loss of their employees.

Uncertainty about the effect of the Merger on employees, customers and suppliers may have an adverse effect on C&J and the C&P Business and, consequently, on surviving entity. These uncertainties may impair C&J’s and the C&P Business’s abilities to attract, retain and motivate key personnel until the Merger is consummated and for a period of time thereafter. These uncertainties could cause customers, suppliers and others who deal with C&J and the C&P Business to change their existing business relationships, which could negatively affect revenues, earnings and cash flows of C&J and the C&P Business, as well as the market price of C&J common stock, regardless of whether the Merger is completed. Employee retention may be challenging during the pendency of the Merger because employees may experience uncertainty about their future roles with the combined company. If, despite the retention efforts of C&J and the C&P Business, key employees depart because of issues relating to the uncertainty around employment security and difficulty of integration or a desire not to remain with the surviving entity, our business could be seriously harmed. In addition, the loss of the services of one or more of these key employees or skilled workers could adversely affect our future operating results because of their experience and knowledge of C&J or the C&P Business.

 

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Risks Related to Our Common Stock

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

The market price of common stock of companies engaged in the oil and gas services industry has been highly volatile. Likewise, the market price of our common stock has varied significantly in the past (52-week range has been $9.11 to $34.93), and we expect it to continue to remain volatile given the cyclical nature of our industry.

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

In the future, we may, from time to time, issue additional shares of common stock or securities convertible into shares of our common stock in public offerings or privately negotiated transactions. As of February 13, 2015, we had 55,208,701 shares of common stock outstanding. We are currently authorized to issue up to 100,000,000 shares of common stock and 20,000,000 shares of preferred stock with terms designated by our Board of Directors. The potential issuance of additional shares of common stock or convertible securities could lower the trading price of our common stock and may dilute your ownership interest in us.

Provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

The existence of some provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company that a stockholder may consider favorable, which could adversely affect the price of our common stock. The provisions in our certificate of incorporation and bylaws that could delay or prevent an unsolicited change in control of our company include board authority to issue preferred stock without stockholder approval, and advance notice provisions for director nominations or business to be considered at a stockholder meeting. In addition, we are governed by Section 203 of the Delaware General Corporation Law, which prohibits us from engaging in any business combination with an interested stockholder for a period of three years from the date the person became an interested stockholder, unless certain conditions are met. These provisions may also discourage acquisition proposals or delay or prevent a change in control, which could harm our stock price.

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

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

 

Item 1B. Unresolved Staff Comments

None.

 

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Item 2. Properties

Our corporate headquarters are located at 3990 Rogerdale Rd., Houston, Texas 77042. In February 2013, we entered into a “build-to-suit” lease agreement with an option to purchase providing for the immediate construction of the 125,000 square feet office park that now serves as our corporate headquarters. The lease for the corporate headquarters facility commenced upon completion of construction in March 2014, creating a capital lease obligation of $25.6 million.

We own or lease facilities and administrative offices throughout the geographic regions in which we operate. As of February 13, 2015, we owned or leased the following additional principal properties:

 

Location

 

Type of Facility

 

Size

 

Lease or

Owned

 

Expiration of Lease

 

Primary

Business Use

4460 Hwy 77

Robstown, TX

 

Administrative offices,

warehouse,

maintenance shop,

equipment yard

 

15 acres, 61,000 sq.

ft. building space

  Owned    

Stimulation &

Well Intervention

Services

6913 N. FM 1788

Midland, TX

 

Administrative offices,

maintenance shop,

equipment yard

 

27.83 acres, 69,000 sq.

ft. building space

  Owned    

Stimulation &

Well Intervention

Services

5604 Medco Dr.

Marshall, TX

 

Administrative offices,

maintenance shop,

equipment yard

 

14 acres, 37,000 sq.

ft. building space

 

Land - Leased

Building - Owned

  December 18, 2021  

Stimulation &

Well Intervention

Services

301 Venture Road

Sayre, OK

 

Administrative offices,

maintenance shop,

equipment yard

 

20 acres, 54,700 sq.

ft. building space

 

Land - Leased

Building - Owned

  October 16, 2025  

Stimulation &

Well Intervention

Services

11700 Onyx Drive

Midland, TX

 

Administrative offices,

maintenance shop,

equipment yard

 

7 acres, 22,124 sq.

ft. building space

  Owned     Wireline Services

940 Gateway Drive

San Angelo, TX

 

Administrative offices,

maintenance shop,

equipment yard

 

20 acres, 20,237 sq.

ft. building space

(under construction)

  Owned     Wireline Services

4700 Commerce

Street Weatherford, OK

 

Administrative offices,

maintenance shop,

equipment yard

 

6 acres, 20,000 sq. ft.

building space

  Lease   October 31, 2018   Wireline Services

701 Industrial

Parkway Muncy, PA

 

Administrative offices,

maintenance shop,

equipment yard

 

6 acres, 13,500 sq. ft.

building space

  Lease   August 30, 2022  

Stimulation &

Well Intervention

Services and

Wireline Services

 

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Location

 

Type of Facility

 

Size

 

Lease or

Owned

 

Expiration of Lease

 

Primary

Business Use

110 29th Street W

Dickinson, ND

 

Administrative offices,

maintenance shop,

equipment yard

 

5 acres, 18,400 sq. ft.

building space

  Lease   August 31, 2020  

Stimulation &

Well Intervention

Services and

Wireline Services

Plot No. S40320 &

S40321 Dubai, UAE

 

Administrative offices,

maintenance shop,

equipment yard

 

14 acres, 104,755 sq.

ft. building space

(under construction)

  Lease   June 30, 2028   International

Media One Tower,

Plot A008-001 Media

City, Dubai, UAE

  Corporate office  

12,920 sq. ft.

building space

  Lease   July 14, 2016   International

5700 Enterprise Drive

Greenville, TX

 

Administrative offices,

warehouse, inventory

management center

 

17 acres, 123,200 sq.

ft. building space

  Owned    

Distribution

Center

4801 Glen Rose Hwy,

Granbury, TX

 

Administrative offices,

warehouse, equipment

manufacturing & repair

facility

 

18 acres, 64,445 sw.

ft. building space

  Owned    

Equipment

Manufacturing

10771 Westpark

Drive Houston, TX

 

Administrative offices,

R&T Lab & Tech Center

 

84,023 sq. ft.

building space

 

Leased - Option

to Purchase

  October 31, 2025   Research & Technology
3990 Rogerdale Road   Administrative offices  

125,000 sq. ft.

building space

  Lease   February 21, 2025   Stimulation & Well Intervention Services

2828 Junipero Avenue

Signal Hill, CA

 

Operations, Staging

and Storage

 

43,775 sq. ft.

building space

  Lease   May 31, 2017   Wireline Services

#210 26229 TWP Rd

531A, 2nd Floor

Acheson, Alberta

  Administrative offices  

2,400 sq. ft.

building space

  Lease   August 1, 2017   Equipment Manufacturing

#101A, 26230 TWP

Rd 531A, Bays 7,8,9

and 10, Acheson,

Alberta

  Administrative offices  

18,750 sq. ft.

building space

  Lease   May 1, 2017   Equipment Manufacturing

1600 South CR 1310

Odessa TX

  Administrative offices  

3 acres, 11,550 sq. ft.

building space

  Owned     Drilling

In addition to the principal properties listed above, we own or lease numerous other smaller facilities across our operating areas, including local sales offices and temporary facilities to house employees in regions where infrastructure is limited. Our leased properties are subject to various lease terms and expirations.

 

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We believe that all of our existing properties are suitable for their intended uses and sufficient to support our operations. We do not believe that any single property is material to our operations and, if necessary, we could readily obtain a replacement facility. We continuously evaluate the needs of our business, and we will purchase or lease additional properties or consolidate our properties, as our business requires.

 

Item 3. Legal Proceedings

Following the June 25, 2014 announcement that C&J, Nabors, and Red Lion had entered into the Merger Agreement, a purported stockholder of C&J filed a lawsuit against C&J, the C&J board of directors, Nabors and Red Lion challenging the Merger. The lawsuit is styled City of Miami General Employees’ and Sanitation Employees’ Retirement Trust, et al. (“Plaintiff”) v. C&J Energy Services, Inc., et al.; C.A. No. 9980-VCN, in the Court of Chancery of the State of Delaware, filed on July 30, 2014 (the “Lawsuit”). Plaintiff in the Lawsuit generally alleges that the C&J board of directors breached fiduciary duties of loyalty, due care, good faith, candor and independence owed to C&J stockholders by allegedly approving the Merger Agreement at an unfair price and through an unfair process. Plaintiff specifically alleges that the C&J board directors, or certain of them (i) failed to fully inform themselves of the market value of C&J, maximize its value and obtain the best price reasonably available for C&J, (ii) acted in bad faith and for improper motives, (iii) erected barriers to discourage other strategic alternatives and (iv) put their personal interests ahead of the interests of C&J stockholders. The Lawsuit further alleges that C&J, Nabors and Red Lion aided and abetted the alleged breaches of fiduciary duties by the C&J board of directors.

Plaintiff in the Lawsuit seeks, among other relief, to enjoin the Merger and the stockholder meeting, rescission in the event the Merger is consummated and an award of costs and disbursements, including reasonable attorneys’ and experts’ fees. On November 10, 2014, Plaintiff filed a motion for a preliminary injunction. On November 24, 2014, the Court of Chancery entered a bench ruling, followed by a written order on November 25, 2014, that (i) ordered certain members of the C&J board of directors to solicit for a period of 30 days alternative proposals to purchase C&J (or a controlling stake in C&J) that are superior to the Pending Nabors Transaction, and (ii) preliminarily enjoined C&J from holding its stockholder meeting until it had complied with the foregoing. The order provided that the solicitation of proposals consistent with the order, and any subsequent negotiations of any alternative proposal that emerges, would not constitute a breach of the Merger Agreement in any respect.

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

On November 26, 2014, the C&J defendants filed a notice of appeal of the Court of Chancery’s order to the Supreme Court of the State of Delaware and moved for expedited proceedings on the appeal. Nabors and Red Lion separately filed a notice of appeal and moved for an expedited appeal as well. On December 1, 2014, the Delaware Supreme Court consolidated the appeals. Oral argument before an en banc bench occurred on December 17, 2014. On December 19, 2014, following oral argument, the Delaware Supreme Court overturned the decision of the Court of Chancery and vacated the order. As such, C&J’s special committee immediately discontinued the solicitation required by the order.

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

 

Item 4. Mine Safety Disclosures

Not applicable.

 

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PART II

 

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

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

Our common stock is traded on the NYSE under the symbol “CJES.” As of February 13, 2015, we had 55,208,701 shares of common stock issued and outstanding, held by approximately 18 record holders. The number of registered holders does not include holders that have shares of common stock held for them in “street name”, meaning that the shares are held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that have shares held in “street name” are not.

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

 

     High      Low  

Year Ended December 31, 2013

     

Quarter ended March 31, 2013

     25.35         21.09   

Quarter ended June 30, 2013

     22.72         17.45   

Quarter ended September 30, 2013

     22.18         18.90   

Quarter ended December 31, 2013

     24.70         19.88   

Year Ended December 31, 2014

     

Quarter ended March 31, 2014

     29.73         20.26   

Quarter ended June 30, 2014

     34.93         27.41   

Quarter ended September 30, 2014

     34.18         26.90   

Quarter ended December 31, 2014

     30.81         11.38   

Period from January 1, 2015 to February 13, 2015

     13.49         9.11   

On February 13, 2015, the last reported sales price of our common stock on the NYSE was $12.98 per share.

We have not declared or paid any cash dividends on our common stock. We currently intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. Payments of dividends, if any, will be at the discretion of our Board and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our Board. Additionally, covenants contained in our Credit Facility restrict the payment of cash dividends on our common stock. Please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Description of our Indebtedness.”

Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

None.

 

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Purchases of Equity Securities by the Issuer or Affiliated Purchasers

Stock Repurchase Program

On October 30, 2013, we announced that our Board of Directors had authorized a common stock repurchase program, pursuant to which we may repurchase up to an aggregate $100 million of C&J’s common stock through December 31, 2015 (the “Repurchase Program”). Any repurchases will be implemented through open market transactions or in privately negotiated transactions, in accordance with applicable securities laws. The timing, price, and size of any repurchases will be made at the Company’s discretion and will depend upon prevailing market prices, general economic and market conditions, the capital needs of the business and other considerations. The Repurchase Program does not obligate us to acquire any particular amount of stock and any repurchases may be commenced or suspended at any time without notice. At each of December 31, 2014 and February 13, 2015, no shares of common stock had been repurchased under the Repurchase Program.

Repurchases of Equity Securities

The following table summarizes stock repurchase activity for the fiscal year ended December 31, 2014 (in thousands, except average price paid per share). All of the repurchases below are shares that were withheld by us to satisfy tax withholding obligations of employees that arose upon the vesting of restricted stock. The value of such shares is based on the closing price of our common stock on the vesting date. As noted above, we have not made any repurchases as of February 13, 2015, under our Repurchase Program.

 

     Total Number
of Shares
Purchased (a)
     Average
Price
Paid Per
Share
     Total Number of Shares
Purchased as Part of
Publicly Announced
Program
     Maximum Number of
Shares that may yet be
Purchased Under
Such Program
 

January 1—January 31

     —           —           —           —     

February 1—February 28

     72,578       $ 24.15         —           —     

March 1—March 31

     358         26.03         —           —     

April 1—April 30

     7,343         29.35         —           —     

May 1—May 31

     —           —           —           —     

June 1—June 30

     68,177         32.62         —           —     

July 1—July 31

     1,981         32.65         —           —     

August 1—August 31

     594         29.75         —           —     

September 1—September 30

     198         28.04         —           —     

October 1—October 31

     925         27.95         —           —     

November 1—November 30

     1,159         18.71         —           —     

December 1—December 31

     —           —           —           —     

 

(a) Represents shares that were withheld by us to satisfy tax withholding obligations of employees that arose upon the vesting of restricted stock. The value of such shares is based on the closing price of our common stock on the vesting date.

 

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Item 6. Selected Financial Data

This section presents our selected consolidated financial data for the periods and as of the dates indicated. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. The following selected consolidated financial data should be read in conjunction with both Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8 “Financial Statements and Supplementary Data” of this Form 10-K in order to understand factors, such as business combinations, which may affect the comparability of the Selected Financial Data:

 

     Years Ended December 31,  
     2014      2013      2012      2011      2010  
     (In thousands except per share amounts)  

Revenue

   $ 1,607,944       $ 1,070,322       $ 1,111,501       $ 758,454       $ 244,157   

Net income

     68,823         66,405         182,350         161,979         32,272   

Net income per common share

              

Basic

     1.28         1.25         3.51         3.28         0.70   

Diluted

     1.22         1.20         3.37         3.19         0.67   

Total assets

     1,612,746         1,132,300         1,012,757         537,849         226,088   

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

     349,875         164,205         173,705         —           44,817   

 

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

The following discussion and analysis of our financial condition and results of operations is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with the audited consolidated financial statements and the related notes thereto included elsewhere in this Form 10-K.

This section contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in any forward-looking statement because of various factors, including, without limitation, those described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors” of this Form 10-K.

Overview

C&J Energy Services, Inc. is a publicly traded corporation listed on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” We were founded in Texas in 1997 as a partnership, and reorganized as a Texas corporation in 2006. In December 2010, we converted to a Delaware corporation in connection with our initial public offering, which we completed in August 2011. References to “C&J,” the “Company,” “we,” “us” or “our” in this report are to C&J Energy Services, Inc. together with its consolidated subsidiaries.

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 10-K or any other report that we may file with or furnish to the SEC.

 

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Pending Transaction to Combine with the Completion and Production Services Business of Nabors Industries, Ltd.

On June 25, 2014, we entered into an agreement and plan of merger (as amended from time to time, the “Merger Agreement”) with Nabors Industries Ltd., a Bermuda exempted company (“Nabors”), and Nabors Red Lion Limited, a Bermuda exempted company and a wholly owned subsidiary of Nabors (“Red Lion”), pursuant to which and subject to the terms thereof, a wholly owned Delaware subsidiary of Red Lion (“Merger Sub”) will merge with and into C&J with C&J surviving as a wholly owned subsidiary of Red Lion (the “Merger”). Prior to the Merger, Nabors will undergo a restructuring pursuant to a Separation Agreement dated as of June 25, 2014 by and between Nabors and Red Lion (as amended from time to time, the “Separation Agreement”) to separate Nabors’ completion and production services business in the U.S. and Canada (“C&P Business”) from the other businesses of Nabors, as a result of which Red Lion will own solely C&P Business (the “Separation”). The transactions contemplated by the Merger Agreement, Separation Agreement and the other agreements contemplated thereby are collectively referred to as the “Pending Nabors Transaction.”

In the Merger, each share of our common stock (other than any treasury shares and shares owned by Red Lion) will be converted into the right to receive one Red Lion common share. It is currently expected that, immediately following the closing of the Merger (“Closing”), former C&J stockholders will own approximately 47% of the issued and outstanding Red Lion common shares and Nabors will own approximately 53% of the issued and outstanding Red Lion common shares. At Closing, the authorized share capital of Red Lion will consist of 750 million common shares and 50 million preferred shares. When the Merger is completed, Red Lion (which will then own both the C&P Business and C&J) will be renamed C&J Energy Services, Ltd. and is expected to be listed on the NYSE under the ticker symbol CJES.

On February 6, 2015, Nabors and Red Lion, with the consent of C&J, entered into Amendment No. 1 to the Separation Agreement (the “Separation Agreement Amendment”). The Separation Agreement Amendment provides for, among other things, a $250 million reduction in the cash payment to be made by subsidiaries of Red Lion to Nabors in connection with the closing of the Merger. As a result, upon the closing of the Merger, Nabors will receive total consideration comprised of approximately $688 million in cash and approximately 62.5 million Red Lion common shares. The value of such consideration to be paid to Nabors at closing was $1.5 billion as of February 13, 2015, with the approximately 62.5 million Red Lion common shares valued based on the closing price on the NYSE for C&J’s common stock on such date. C&J has obtained commitments from certain financial institutions to provide debt financing to Red Lion and/or certain of its subsidiaries in an amount sufficient to fund the payment of the cash consideration at Closing.

Additionally, on February 6, 2015, the parties to the Merger Agreement entered into Amendment No. 1 to the Merger Agreement (the “Merger Agreement Amendment”). The Merger Agreement Amendment revises the descriptions of the tax opinions to be delivered by each of Nabors’ and C&J’s respective tax advisors in connection with the closing of the Merger. The tax opinion to be delivered to Nabors will be required to state that the distribution of Nabors Completion & Production Services Co. by Nabors International Finance Inc. to Nabors Blue Shield Ltd. is subject to the possible application of Section 355(d) of the Internal Revenue Code (the “Code”). The tax opinion to be delivered to C&J will be required to state that it is more likely than not that (i) the Merger qualifies as a reorganization within the meaning of Section 368(a) of the Code, and (ii) Red Lion qualifies as a corporation under Section 367(a) of the Code with respect to each transfer of property in connection with the Merger (with certain exceptions). Additionally, the Merger Agreement Amendment provides that if Nabors fails to deliver certain required financial information to C&J on or before the close of business on March 3, 2015, Nabors will not be entitled to recover a $65 million termination fee in the event C&J’s financing arrangements are not available to close the Merger. Finally, the Merger Agreement Amendment requires C&J to request

 

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each person treated as a “5-percent transferee shareholder” (as defined in the Treasury Regulations) enter into a “gain recognition agreement” (as defined in the Treasury Regulations) following the closing of the Merger.

Closing of the Pending Nabors Transaction is subject to customary closing conditions, including, among others, (1) the consummation of the Separation in accordance with the Separation Agreement; (2) the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (“HSR”), which termination occurred on July 28, 2014; (3) approval by C&J’s stockholders; (4) the registration statement on Form S-4 (the “S-4”) used to register the Red Lion common shares to be issued in the Merger, which includes a preliminary prospectus of Red Lion and a preliminary proxy statement of C&J, being declared effective by the SEC, which effectiveness was granted on February 13, 2015; (5) the approval for listing on the NYSE of the Red Lion common shares to be issued in the Merger; (6) subject to specified materiality standards, the accuracy of the representations and warranties of, and the performance of all covenants in the Merger Agreement, Separation Agreement and related closing documents by, the parties thereto; (7) the absence of a material adverse effect as defined in the Merger Agreement with respect to each of C&J and Red Lion; (8) the availability of the proceeds of the debt financing to effect the repayment of certain intercompany notes issued by subsidiaries of Red Lion to other subsidiaries of Nabors in connection with the Separation; (9) the receipt of consents, approvals and other deliverables with respect to certain agreements of C&J; (10) the receipt by Nabors of an opinion from its counsel to the effect that certain aspects of the Separation should qualify as tax-free pursuant to Section 355 of the Code; and (11) the receipt by C&J of an opinion from its counsel to the effect that it is more likely than not that (i) the Merger qualifies as a reorganization within the meaning of Section 368(a) of the Code and (ii) Red Lion qualifies as a corporation within the meaning of Section 367(a) of the Code.

On February 13, 2015, the S-4 was declared effective by the SEC, and we filed a definitive proxy statement dated February 13, 2015 with the SEC on that date. Mailing of the proxy statement, together with the Notice of Special Meeting and proxy card, to C&J stockholders of record on the record date commenced on February 13, 2015. The special meeting of C&J stockholders for purposes of approving the Pending Nabors Transaction and other matters detailed in the proxy statement will be held on March 20, 2015.

We currently expect the Closing to occur in March 2015, subject to approval of the Merger Agreement by C&J stockholders and other customary closing items. There can be no assurance as to whether or when the Closing will occur.

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:

 

    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.

 

    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.

 

    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.

 

   

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

We currently operate 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” 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 Pending Nabors Transaction 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 Pending Nabors Transaction, 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 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 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 Pending Nabors Transaction, 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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In the event that the Pending Nabors Transaction is not consummated, our existing Credit Facility (as defined and described in more detail under “Description of Our Indebtedness” and in “Note 2 – Long-Term Debt and Capital Lease Obligations” in Item 8 “Financial Statements and Supplementary Data”) provides for up to $500.0 million of revolving credit. In November 2014, the Company 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 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 Pending Nabors Transaction, the substantial indebtedness that will be incurred in connection with the Pending Nabors Transaction, 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 Pending Nabors Transaction, 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 Pending Nabors Transaction, 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.

In the event that the Pending Nabors Transaction is not consummated, we believe our cash flows from operations and existing capital, coupled with borrowings under our existing Credit Facility, will be sufficient to fund our planned 2015 capital expenditures and sustain our spending levels over the next 12 months. We increased the borrowing base under our Credit Facility to $500.0 million from $400.0 million by exercising the Credit Facility’s accordion feature in November of 2014. As of February 13, 2015, $155.3 million was available for borrowing.

At closing of the Pending Nabors Transaction, 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

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” 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.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is commodity price risk, which is the risk related to increases in the prices of fuel, materials and supplies consumed in performing our services. We are also exposed to risks related to interest rate fluctuations and customer credit.

Commodity Price Risk. Our material and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation services such as proppants, chemicals, guar, coiled tubing and fluid supplies. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw

 

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materials (particularly guar and proppants) in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Historically, we have generally been able to pass along price increases to our customers, however, we may be unable to do so in the future. We do not engage in commodity price hedging activities.

Interest Rate Risk. We are exposed to changes in interest rates on our floating rate borrowings under our Credit Facility. The impact of a 1% increase in interest rates on our outstanding debt as of December 31, 2014 and 2013 would have resulted in an increase in interest expense and a corresponding decrease in net income of approximately $3.2 million and $1.5 million, respectively.

Customer Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk are trade receivables. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including credit evaluations and maintaining an allowance for doubtful accounts.

 

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Item 8. Financial Statements and Supplementary Data

Index to

Consolidated Financial Statements

 

Management’s Report on Internal Control Over Financial Reporting

  76   

Reports of Independent Registered Public Accounting Firms

  77   

Consolidated Balance Sheets as of December 31, 2014 and 2013

  80   

Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012

  81   

Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December  31, 2014, 2013 and 2012

  82   

Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

  83   

Notes to Consolidated Financial Statements

  84   

 

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Management’s Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act). Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States and includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management with the participation of the Company’s principal executive and financial officers assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014 using the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (1992). Management’s assessment included an evaluation of the design of internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Based on this assessment, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2014.

Management’s assessment of the Company’s internal control over financial reporting as of December 31, 2014 excluded the internal control over financial reporting of Tiger Casedhole Services, Inc. (“Tiger”), which was acquired on May 30, 2014. Tiger represented approximately 1% of consolidated revenues and 3% of consolidated total assets as of December 31, 2014.

The Company’s internal control over financial reporting as of December 31, 2014 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears herein.

 

/s/ Joshua E. Comstock

/s/ Randall C. McMullen, Jr.

/s/ Mark C. Cashiola

Joshua E. Comstock

Chairman and Chief Executive

Officer (Principal Executive Officer)

Randall C. McMullen, Jr.

President and Chief Financial

Officer (Principal Financial Officer)

Mark C. Cashiola

Vice President and Controller

(Principal Accounting Officer)

February 20, 2015

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

C&J Energy Services, Inc.:

We have audited the accompanying consolidated balance sheet of C&J Energy Services, Inc. and subsidiaries as of December 31, 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of C&J Energy Services, Inc. and subsidiaries as of December 31, 2014, and the results of their operations and their cash flows for the year ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), C&J Energy Services, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 20, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. This report contains an explanatory paragraph stating that C&J Energy Services, Inc. acquired Tiger Cased Hole Services, Inc. (Tiger) during 2014 and management excluded from its assessment of the effectiveness of C&J Energy Services, Inc.’s internal control over financial reporting as of December 31, 2014, Tiger’s internal control over financial reporting associated with 1% of consolidated revenues and 3% of consolidated total assets of C&J Energy Services, Inc. as of and for the year ended December 31, 2014. Our audit of internal control over financial reporting of C&J Energy Services, Inc. also excluded an evaluation of the internal control over financial reporting of Tiger.

(signed) KPMG LLP

Houston, Texas

February 20, 2015

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

C&J Energy Services, Inc.:

We have audited C&J Energy Services, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). C&J Energy Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, C&J Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

C&J Energy Services, Inc. acquired Tiger Cased Hole Services, Inc. (Tiger) during 2014, and management excluded from its assessment of the effectiveness of C&J Energy Services, Inc.’s internal control over financial reporting as of December 31, 2014, Tiger’s internal control over financial reporting associated with 1% of consolidated revenues and 3% of consolidated total assets of C&J Energy Services, Inc. as of and for the year ended December 31, 2014. Our audit of internal control over financial reporting of C&J Energy Services, Inc. also excluded an evaluation of the internal control over financial reporting of Tiger.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of C&J Energy Services, Inc. and subsidiaries as of December 31, 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2014, and our report dated February 20, 2015 expressed an unqualified opinion on those consolidated financial statements.

(signed) KPMG LLP

Houston, Texas

February 20, 2015

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

C&J Energy Services, Inc.

We have audited the accompanying consolidated balance sheet of C&J Energy Services, Inc. (a Delaware corporation) and subsidiaries (collectively, the “Company”) as of December 31, 2013, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the two years in the period ended December 31, 2013. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

/s/ UHY LLP

Houston, Texas

February 26, 2014

 

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Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share data)

 

     As of December 31,  
     2014      2013  

ASSETS

     

Current assets:

     

Cash and cash equivalents

   $ 10,017       $ 14,414   

Accounts receivable, net

     290,767         152,696   

Inventories, net

     122,172         70,946   

Prepaid and other current assets

     29,525         17,066   

Deferred tax assets

     8,106         1,722   
  

 

 

    

 

 

 

Total current assets

  460,587      256,844   

Property, plant and equipment, net

  783,302      535,574   

Other assets:

Goodwill

  219,953      205,798   

Intangible assets, net

  129,468      123,038   

Deposits on equipment under construction

  7,117      4,331   

Deferred financing costs, net

  3,786      2,688   

Other noncurrent assets

  8,533      4,027   
  

 

 

    

 

 

 

Total assets

$ 1,612,746    $ 1,132,300   
  

 

 

    

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable

$ 229,191    $ 88,576   

Accrued payroll and related costs

  16,047      13,711   

Accrued expenses

  30,794      18,619   

Income taxes payable

  —        266   

Current capital lease obligations

  3,873      2,860   

Other current liabilities

  4,926      1,101   
  

 

 

    

 

 

 

Total current liabilities

  284,831      125,133   

Deferred tax liabilities

  193,340      145,215   

Long-term debt and capital lease obligations

  349,875      164,205   

Other long-term liabilities

  2,803      1,596   
  

 

 

    

 

 

 

Total liabilities

  830,849      436,149   

Commitments and contingencies

Stockholders’ equity

Common stock, par value of $0.01, 100,000,000 shares authorized, 55,333,392 issued and outstanding at December 31, 2014 and 54,604,124 issued and outstanding at December 31, 2013

  553      546   

Additional paid-in capital

  271,104      254,188   

Retained earnings

  510,240      441,417   
  

 

 

    

 

 

 

Total stockholders’ equity

  781,897      696,151   
  

 

 

    

 

 

 

Total liabilities and stockholders’ equity

$ 1,612,746    $ 1,132,300   
  

 

 

    

 

 

 

See accompanying notes to consolidated financial statements

 

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Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands, except per share data)

 

     Years Ended December 31,  
     2014     2013     2012  

Revenue

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

Costs and expenses:

      

Direct costs

     1,162,708        738,962        686,811   

Selling, general and administrative expenses

     199,037        136,910        94,556   

Research and development

     14,327        5,005        —     

Depreciation and amortization

     108,145        74,703        46,912   

(Gain) loss on disposal of assets

     (17     527        692   
  

 

 

   

 

 

   

 

 

 

Operating income

  123,744      114,215      282,530   

Other income (expense):

Interest expense, net

  (9,840   (6,550   (4,996

Other income (expense), net

  598      53      (105
  

 

 

   

 

 

   

 

 

 

Total other income (expense)

  (9,242   (6,497   (5,101
  

 

 

   

 

 

   

 

 

 

Income before income taxes

  114,502      107,718      277,429   

Income tax expense

  45,679      41,313      95,079   
  

 

 

   

 

 

   

 

 

 

Net income

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

 

 

   

 

 

   

 

 

 

Net income per common share:

Basic

$ 1.28    $ 1.25    $ 3.51   
  

 

 

   

 

 

   

 

 

 

Diluted

$ 1.22    $ 1.20    $ 3.37   
  

 

 

   

 

 

   

 

 

 

Weighted average common shares outstanding:

Basic

  53,838      53,038      52,008   
  

 

 

   

 

 

   

 

 

 

Diluted

  56,513      55,367      54,039   
  

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(Amounts in thousands)

 

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

Balance, December 31, 2011

     51,887      $ 519      $ 201,874      $ 192,662       $ 395,055   

Issuance of restricted stock, net of forfeitures

     780        7        (7     —           —     

Exercise of stock options

     465        5        2,568        —           2,573   

Tax effect of stock-based compensation

     —          —          1,901        —           1,901   

Stock-based compensation

     —          —          18,012        —           18,012   

Net income

     —          —          —          182,350         182,350   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Balance, December 31, 2012

  53,132      531      224,348      375,012      599,891   

Issuance of restricted stock, net of forfeitures

  669      7      (7   —        —     

Employee tax withholding on restricted stock vesting

  (74   (1   (1,374   —        (1,375

Exercise of stock options

  877      9      5,210      —        5,219   

Tax effect of stock-based compensation

  —        —        3,430      —        3,430   

Stock-based compensation

  —        —        22,581      —        22,581   

Net income

  —        —        —        66,405      66,405   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Balance, December 31, 2013

  54,604      546      254,188      441,417      696,151   

Issuance of restricted stock, net of forfeitures

  723      7      (7   —        —     

Employee tax withholding on restricted stock vesting

  (153   (2   (4,376   —        (4,378

Exercise of stock options

  159      2      831      —        833   

Tax effect of stock-based compensation

  —        —        2,118      —        2,118   

Stock-based compensation

  —        —        18,350      —        18,350   

Net income

  —        —        —        68,823      68,823   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Balance, December 31, 2014

  55,333    $ 553    $ 271,104    $ 510,240    $ 781,897   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

See accompanying notes to consolidated financial statements

 

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Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

 

     Years Ended December 31,  
     2014     2013     2012  

Cash flows from operating activities:

      

Net income

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

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation and amortization

     108,145        74,703        46,912   

Deferred income taxes

     33,185        16,513        15,926   

Provision for doubtful accounts, net of write-offs

     600        689        600   

Equity (earnings) loss from unconsolidated affiliate

     (471     160        —     

(Gain) Loss on disposal of assets

     (17     527        692   

Stock-based compensation expense

     18,350        22,581        18,012   

Amortization of deferred financing costs

     1,168        1,160        923   

Inventory write-down

     —          870        —     

Changes in operating assets and liabilities:

      

Accounts receivable

     (135,784     14,704        (10,621

Inventories

     (50,001     (10,495     (11,263

Prepaid expenses and other current assets

     (12,154     (12,405     7,107   

Accounts payable

     132,420        11,991        (1,195

Payroll and related costs and accrued expenses

     14,157        2,710        5,373   

Income taxes payable

     (301     (3,888     1,765   

Other

     3,717        (5,124     (2,651
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

  181,837      181,101      253,930   
  

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

Purchases of and deposits on property, plant and equipment

  (307,598   (151,810   (181,426

Proceeds from disposal of property, plant and equipment

  719      1,151      434   

Payments made for business acquisitions, net of cash acquired

  (33,533   (14,636   (273,401

Investment in unconsolidated subsidiary

  (3,000   —        (3,000
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

  (343,412   (165,295   (457,393
  

 

 

   

 

 

   

 

 

 

Cash flows from financing activities:

Proceeds from revolving debt

  229,000      60,000      245,000   

Payments on revolving debt

  (64,000   (80,306   (75,000

Payments of long-term debt

  —        (638   —     

Payments of capital lease obligations

  (4,165   (2,184   (1,121

Financing costs

  (2,265   —        (2,243

Proceeds from stock options exercised

  833      5,219      2,573   

Employee tax withholding on restricted stock vesting

  (4,378   (1,375   —     

Excess tax benefit from stock-based award activity

  2,153      3,450      1,916   
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

  157,178      (15,834   171,125   
  

 

 

   

 

 

   

 

 

 

Net decrease in cash and cash equivalents

  (4,397   (28   (32,338

Cash and cash equivalents, beginning of year

  14,414      14,442      46,780   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of year

$ 10,017    $ 14,414    $ 14,442   
  

 

 

   

 

 

   

 

 

 

Supplemental cash flow disclosures:

Cash paid for interest

$ 8,525    $ 5,473    $ 3,975   
  

 

 

   

 

 

   

 

 

 

Cash paid for income taxes

$ 16,125    $ 38,819    $ 75,619   
  

 

 

   

 

 

   

 

 

 

Non-cash investing and financing activity:

Capital lease obligations

$ 25,847    $ 13,487    $ —     
  

 

 

   

 

 

   

 

 

 

Change in accrued capital expenditures

$ 8,120    $ 6,177    $ 753   
  

 

 

   

 

 

   

 

 

 

Non-cash consideration for business acquisition

$ —      $ 2,556    $ —     
  

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements

 

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Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

C&J Energy Services, Inc. is a publicly traded corporation listed on the New York Stock Exchange under the symbol “CJES.” The Company were founded in Texas in 1997 as a partnership, and reorganized as a Texas corporation in 2006. In December 2010, the Company converted to a Delaware corporation in connection with its initial public offering, which was completed in August 2011. C&J Energy Services, Inc. is a holding company and substantially all of its operations are conducted through, and substantially all of its assets are held by its primary operating subsidiary, C&J Spec-Rent Services, Inc. Through its subsidiaries, the Company operates in three reportable segments: Stimulation and Well Intervention Services, Wireline Services and Equipment Manufacturing. The Company provides hydraulic fracturing, coiled tubing and other well stimulation services, as well as directional drilling services, through its Stimulation and Well Intervention Services segment and cased-hole wireline, pumpdown and other complementary services through its Wireline Services segment to oil and natural gas exploration and production companies throughout the United States. With the development of a specialty chemicals business and strategic acquisitions during 2013, the Company now blends and supplies specialty chemicals for completion and production services, and also manufactures and provides downhole tools and related directional drilling technology and data acquisition and control systems through the Stimulation and Well Intervention Services segment. These products are provided to third-party customers in the energy services industry and are also used in the Company’s operations and equipment. In addition, the Company manufactures, refurbishes and repairs equipment and provides oilfield parts and supplies to the energy services industry through its Equipment Manufacturing segment, the majority of which are provided to the Company’s Stimulation and Well Intervention Services segment. See “Note 11 – Segment Information” for further discussion regarding the Company’s reportable segments. As used herein, references to the “Company” or “C&J” are to C&J Energy Services, Inc. together with its consolidated subsidiaries, including C&J International B.V. and C&J International Middle East FZCO.

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

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

Cash and Cash Equivalents. For purposes of the consolidated statement of cash flows, cash is defined as cash on-hand, demand deposits, and short-term investments with initial maturities of three months or less. The Company maintains its cash and cash equivalents in various financial institutions, which at times may exceed federally insured amounts. Management believes that this risk is not significant.

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

 

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Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

Inventories are stated at the lower of cost or market (net realizable value) on a first-in, first-out basis and appropriate consideration is given to deterioration, obsolescence and other factors in evaluating net realizable value. Inventories consisted of the following (in thousands):

 

     As of December 31,  
     2014      2013  

Raw materials

   $ 51,374       $ 31,445   

Work-in-process

     24,408         3,652   

Finished goods

     47,717         36,690   
  

 

 

    

 

 

 

Total inventory

  123,499      71,787   

Inventory reserve

  (1,327   (841
  

 

 

    

 

 

 

Inventory, net of reserve

$ 122,172    $ 70,946   
  

 

 

    

 

 

 

Property, Plant and Equipment. Property, plant and equipment are recorded at cost less accumulated depreciation. Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to expense when incurred. Refurbishments are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operating income.

The cost of property and equipment currently in service is depreciated, on a straight-line basis, over the estimated useful lives of the related assets, which range from three to 25 years. Depreciation expense was $97.2 million, $64.6 million and $39.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. Major classifications of property, plant and equipment and their respective useful lives were as follows (in thousands):

 

     Estimated
Useful Lives
   As of December 31,  
        2014      2013  

Land

   Indefinite    $ 2,453       $ 2,225   

Building and leasehold improvements

   5-25 years      107,270         50,163   

Office furniture, fixtures and equipment

   3-5 years      19,716         10,878   

Machinery and equipment

   3-10 years      767,415         529,854   

Transportation equipment

   5 years      66,456         46,425   
     

 

 

    

 

 

 
  963,310      639,545   

Less: accumulated depreciation

  (245,683   (148,954
     

 

 

    

 

 

 
  717,627      490,591   

Construction in progress

  65,675      44,983   
     

 

 

    

 

 

 

Property, plant and equipment, net

$ 783,302    $ 535,574   
     

 

 

    

 

 

 

 

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Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Impairment of Long-Lived Assets. Long-lived assets, which include property, plant and equipment, and intangible assets with finite lives, are evaluated on a quarterly basis to identify events or changes in circumstances (“triggering events”) that indicate the carrying value of certain long-lived assets may not be recoverable. Long-lived assets are reviewed for impairment upon the occurrence of a triggering event. An impairment loss is recorded in the period in which it is determined that the carrying amount of a long-lived asset is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets with such cash flows to be realized over the estimated remaining useful life of the primary asset within the asset group, excluding interest expense. The Company determined the lowest level of identifiable cash flows that are independent of other asset groups to be at the service line level, which consists of the hydraulic fracturing, coiled tubing, wireline, pumpdown, directional drilling and international coiled tubing service lines. If the estimated undiscounted future net cash flows are less than the carrying amount of the related assets, an impairment loss is determined by comparing the fair value with the carrying value of the related assets.

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

Goodwill, Intangible Assets and Amortization. Goodwill is allocated to the Company’s three reporting units: Stimulation and Well Intervention Services, Wireline Services and Equipment Manufacturing, 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. The Company may also choose to bypass a qualitative approach and opt instead to employ detailed testing methodologies, regardless of a possible more likely than not outcome. Detailed impairment testing involves comparing the fair value of each reporting unit to its carrying value, including goodwill. Fair value reflects the price a market participant would be willing to pay in a potential sale of the reporting unit. If the fair value exceeds carrying value, then it is concluded that no goodwill impairment has occurred. If the carrying value of the reporting unit exceeds its fair value, a second step is required to measure possible goodwill impairment loss. The second step includes hypothetically valuing the tangible and intangible assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Then, the implied fair value of the reporting unit’s goodwill is compared to the carrying value of that goodwill. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess, not to exceed the carrying value.

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.

 

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Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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. The fair values for each of the three reporting units were determined using a blended income and market approach.

Income approach

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

A terminal period was used to reflect an estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 2.5% for all three reporting units, including an estimated inflation factor. The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital (“WACC”) of 15.0% for both Stimulation and Well Intervention Services and Wireline Services and 15.5% for Equipment Manufacturing reporting units. These assumptions were derived from unobservable inputs and reflect management’s judgments and assumptions.

Market approach

The market approach was based upon two methods: the guideline public company method and the guideline transaction method. The application of the guideline public company method was based upon selected public companies operating within the same industry as the Company. Based on this set of comparable competitor data, price-to-earnings multiples were derived and a range of price-to-earnings multiples was determined for each reporting unit. Selected market multiples averaged 3.9x for Stimulation and Well Intervention Services, 3.9x for Wireline Services, and 4.9x for Equipment Manufacturing.

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

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

 

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Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 the goodwill balance of $146.1 million was not impaired; and (iii) the Equipment Manufacturing reporting unit estimated fair value exceeded its carrying value by approximately 48%, and it was concluded that the goodwill balance of $4.7 million was not impaired. As a way to validate the estimated reporting unit fair values, the total market capitalization of the Company was compared to the total estimated fair value of all reporting units, and an implied control premium was derived. Market data in support of the implied control premium was used in this reconciliation to corroborate the estimated reporting unit fair values.

A decline in any of the three reporting unit cash flow projections or changes in other key assumptions may result in a goodwill impairment charge in the future.

Indefinite-lived intangible assets

The Company has approximately $13.8 million of intangible assets with indefinite useful lives, which are subject to annual impairment tests or more frequently if events or circumstances indicate the carrying amount may not be recoverable. Before employing detailed impairment testing methodologies, the Company may first evaluate the likelihood of impairment by considering qualitative factors. A detailed impairment test for indefinite lived intangible assets encompasses calculating the fair value of an indefinite lived intangible asset and comparing the fair value to its carrying value.

The sharp fall in commodity prices that occurred during the second half of 2014 was deemed a triggering event and detailed impairment testing was performed on the Total Equipment trade name using a relief from royalty method. Based on the results of the impairment testing, the trade name estimated fair value exceeded its carrying value by approximately 55% and it was determined that the trade name carry value of $6.2 million was not impaired as of December 31, 2014.

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.

 

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Intangible assets consisted of the following (in thousands):

 

     Amortization
Period
   As of December 31,  
        2014      2013  

Trade name

   10-15 years    $ 29,315       $ 27,665   

Customer relationships

   8-15 years      116,073         100,593   

Non-compete

   4-5 years      1,810         1,600   

Developed technology

   10 years      2,110         2,110   

IPR&D

   Indefinite      7,598         7,598   

Trade name - Total Equipment

   Indefinite      6,247         6,247   
     

 

 

    

 

 

 
  163,153      145,813   

Less: accumulated amortization

  (33,685   (22,775
     

 

 

    

 

 

 

Intangible assets, net

$ 129,468    $ 123,038   
     

 

 

    

 

 

 

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

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

 

Years Ending December 31,

      

2015

   $ 10,774   

2016

     10,507   

2017

     10,374   

2018

     10,374   

2019

     10,350   

Thereafter

     63,244   
  

 

 

 
$ 115,623   
  

 

 

 

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

 

Years Ending December 31,

      

2015

   $ 1,160   

2016

     368   
  

 

 

 
$ 1,528   
  

 

 

 

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

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

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

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

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

Coiled Tubing and Other Well Stimulation Revenue. The Company provides coiled tubing and other well stimulation services, including nitrogen, pressure pumping and thru-tubing services, primarily on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. Revenue is recognized upon completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the services performed and the consumables (such as stimulation fluids, nitrogen and coiled tubing materials) used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables. The Company typically charges the customer for these services and resources on an hourly basis at agreed-upon spot market rates.

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

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

In addition, ancillary to coiled tubing and other well stimulation services revenue, the Company generates revenue from various fluids and supplies that are necessarily consumed during those processes.

Wireline Revenue. The Company provides cased-hole wireline, pumpdown and other complementary services, including logging, perforating, pipe recovery and pressure testing services on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. Revenue is recognized when the services and equipment are provided and the job is completed. The Company typically charges the customer on a per job basis for these services at agreed-upon spot market rates.

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

Stock-Based Compensation. The Company’s stock-based compensation plans provide the ability to grant equity awards to the Company’s employees, consultants and non-employee directors. As of December 31, 2014, only nonqualified stock options and restricted stock had been granted under such plans. The Company values option grants based on the grant date fair value by using the Black-Scholes option-pricing model and values restricted stock grants based on the closing price of C&J’s common stock on the grant date. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. Further information regarding the Company’s stock-based compensation arrangements and the related accounting treatment can be found in “Note 6 – Stock-Based Compensation.”

Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, long-term debt and capital lease obligations. The recorded values of cash and cash equivalents, accounts receivable, and accounts payable approximate their fair values based on their short-term nature. The carrying value of long-term debt and capital lease obligations approximate their fair value, as the interest rates approximate market rates.

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

The carrying value of this equity method investment at December 31, 2014 and December 31, 2013 was $7.0 million and $2.8 million, respectively, and is included in other noncurrent assets on the consolidated balance sheets. The Company’s share of the net income (loss) from the unconsolidated affiliate was approximately $0.5 million and $(0.2 million) for the years ended December 31, 2014 and December 31, 2013, respectively, and is included in other expense, net, on the consolidated statements of operations.

Income Taxes. The Company accounts for income taxes using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income or expense in the period that includes the enactment date.

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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.

The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. However, there were no material amounts recognized relating to interest and penalties in the consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012, respectively. The Company had no uncertain tax positions as of December 31, 2014.

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

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

 

     Years Ended December 31,  
     2014      2013      2012  
     (In thousands, except per share amounts)  

Numerator:

        

Net income attributed to common shareholders

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

 

 

    

 

 

    

 

 

 

Denominator:

Weighted average common shares outstanding - basic

  53,838      53,038      52,008   

Effect of potentially dilutive securities:

Stock options

  2,245      2,096      1,979   

Restricted stock

  430      233      52   
  

 

 

    

 

 

    

 

 

 

Weighted average common shares outstanding - diluted

  56,513      55,367      54,039   
  

 

 

    

 

 

    

 

 

 

Earnings per common share:

Basic

$ 1.28    $ 1.25    $ 3.51   
  

 

 

    

 

 

    

 

 

 

Diluted

$ 1.22    $ 1.20    $ 3.37   
  

 

 

    

 

 

    

 

 

 

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

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

Basic earnings per share:

        

Unvested restricted stock

     1,448         1,194         748   

Diluted earnings per share:

        

Anti-dilutive stock options

     201         1,054         1,193   

Anti-dilutive restricted stock

     3         164         30   
  

 

 

    

 

 

    

 

 

 

Potentially dilutive securities excluded as anti-dilutive

  204      1,218      1,223   
  

 

 

    

 

 

    

 

 

 

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

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

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

Reclassifications and immaterial adjustment. Certain reclassifications have been made to prior period consolidated financial statements to conform to current period presentations. Additionally, an immaterial adjustment has been made to the Company’s consolidated statement of cash flows for the years ended December 31, 2013 and December 31,

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

2012 to decrease previously reported operating cash flows and increase previously reported investing cash flows by $6.2 million and $0.8 million, respectively, to properly reflect the change in accrued capital expenditures on the consolidated statement of cash flows as a supplemental non-cash investing activity. These adjustments had no impact to the Company’s consolidated balance sheet or consolidated statement of operations for the year ended December 31, 2013.

Note 2 - Long-Term Debt and Capital Lease Obligations

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

 

     As of December 31,  
     2014      2013  

Senior secured revolving credit facility maturing on April 19, 2016

   $ 315,000       $ 150,000   

Capital leases

     38,748         17,065   
  

 

 

    

 

 

 

Total debt and capital lease obligations

  353,748      167,065   

Less: amount maturing within one year

  (3,873   (2,860
  

 

 

    

 

 

 

Long-term debt and capital lease obligations

$ 349,875    $ 164,205   
  

 

 

    

 

 

 

Credit Facility

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

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

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

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

Capital Lease Obligations

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

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The lease for the technology facility commenced upon completion of construction in October 2013, creating a capital lease obligation of $13.5 million and accumulated amortization was $0.9 million at December 31, 2014. The lease is payable monthly in amounts ranging from $93 thousand to $128 thousand over the term of the lease, including interest at approximately 2.7% per year, and has an initial term of 12 years. Cumulative future lease payments through the initial term are $15.9 million, of which approximately $2.4 million represents interest expense.

The lease for the corporate headquarters commenced upon completion of construction in April 2014, creating a capital lease obligation of $25.6 million and accumulated amortization was $1.2 million at December 31, 2014. The lease is payable monthly in amounts ranging from $181 thousand to $238 thousand over the term of the lease, including interest at approximately 2.7% per year, and has an initial term of 12 years. Cumulative future lease payments through the initial term are $30.3 million, of which approximately $4.7 million represents interest expense.

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

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

 

Years Ending December 31,

      

2015

   $ 4,875   

2016

     3,734   

2017

     3,584   

2018

     3,685   

2019

     3,785   

Thereafter

     25,272   
  

 

 

 
$ 44,935   
  

 

 

 

Note 3 – Acquisitions

Acquisition of Tiger

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

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

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

Current assets

$ 3,851   

Property and equipment

  8,176   

Goodwill

  14,671   

Other intangible assets

  17,340   
  

 

 

 

Total assets acquired

$ 44,038   
  

 

 

 

Current liabilities

$ 1,223   

Deferred income taxes

  8,556   

Other liabilities

  1,015   
  

 

 

 

Total liabilites assumed

$ 10,794   
  

 

 

 

Net assets acquired

$ 33,244   
  

 

 

 

Acquisition of Casedhole Solutions

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

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

 

Current assets

$ 49,619   

Property and equipment

  73,204   

Goodwill

  131,455   

Other intangible assets

  105,600   

Other assets

  1,459   
  

 

 

 

Total assets acquired

$ 361,337   
  

 

 

 

Current liabilities

$ 23,081   

Capital lease obligations

  4,895   

Deferred income taxes

  52,602   
  

 

 

 

Total liabilites assumed

$ 80,578   
  

 

 

 

Net assets acquired

$ 280,759   
  

 

 

 

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

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

     Years Ended December 31,  
     2012      2011  

Revenues

   $ 1,205,864       $ 886,721   

Net income

     194,716         167,842   

Net income per common share:

     

Basic

   $ 3.74       $ 3.40   

Diluted

     3.60         3.31   

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

Other Acquisitions

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

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

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 4 – Income Taxes

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

 

     Years Ended December 31,  
     2014      2013      2012  

Current provision:

        

Federal

   $ 11,184       $ 22,870       $ 75,205   

State

     1,310         1,930         3,948   
  

 

 

    

 

 

    

 

 

 

Total current provision

  12,494      24,800      79,153   

Deferred (benefit) provision:

Federal

  31,978      14,864      16,199   

State

  2,036      1,705      (273

Foreign

  (829   (56   —     
  

 

 

    

 

 

    

 

 

 

Total deferred provision

  33,185      16,513      15,926   
  

 

 

    

 

 

    

 

 

 

Provision for income taxes

$ 45,679    $ 41,313    $ 95,079   
  

 

 

    

 

 

    

 

 

 

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

 

     Years Ended December 31,  
     2014     2013     2012  

Federal statutory rate

     35.0     35.0     35.0

State taxes, net of federal benefit

     3.0     2.8     1.4

Domestic production activities deduction

     -1.0     -1.8     -2.6

Effect of foreign losses

     2.4     0.7     —     

Other

     0.5     1.7     0.5
  

 

 

   

 

 

   

 

 

 

Effective income tax rate

  39.9   38.4   34.3
  

 

 

   

 

 

   

 

 

 

 

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

     As of December 31,  
     2014      2013  

Deferred tax assets:

     

Accrued liabilities

   $ 5,419       $ 635   

Allowance for doubtful accounts

     822         609   

Stock-based compensation

     1,027         335   

Other

     838         429   
  

 

 

    

 

 

 

Current deferred tax assets

  8,106      2,008   

Stock-based compensation

  16,896      14,577   

Net operating losses

  1,181      750   

Accrued liabilities

  69      93   

Other

  —        123   
  

 

 

    

 

 

 

Non-current deferred tax assets

  18,146      15,543   
  

 

 

    

 

 

 

Total deferred tax assets

  26,252      17,551   

Valuation allowance

  —        —     
  

 

 

    

 

 

 

Total deferred tax assets, net

  26,252      17,551   

Deferred tax liabilities:

Current deferred tax liability

  —        (286

Depreciation on property, plant and equipment

  (161,782   (113,584

Amortization of goodwill and intangible assets

  (49,704   (47,174
  

 

 

    

 

 

 

Non-current deferred tax liabilities

  (211,486   (160,758
  

 

 

    

 

 

 

Net deferred tax liability

$ (185,234 $ (143,493
  

 

 

    

 

 

 

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

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

Note 5 – Stockholders’ Equity

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

 

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Note 6 - Stock-Based Compensation

The C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (the “2012 LTIP”) provides for the grant of stock-based awards to the Company’s officers, employees, consultants and non-employee directors. The following types of awards are available for issuance under the 2012 LTIP: incentive stock options and nonqualified stock options; stock appreciation rights; restricted stock; restricted stock units; dividend equivalent rights; phantom stock units; performance awards; and share awards. To date, only nonqualified stock options and restricted stock have been awarded under the 2012 LTIP. Under the 2012 LTIP, all stock option awards have been granted with an exercise price equal to the market price of the Company’s stock at the grant date. Those awards generally vest over three years of continuous service with one-third vesting on the first, second, and third anniversaries of the option’s grant date. The option awards expire on the tenth anniversary of the date of grant.

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

A total of 4.3 million shares of common stock were authorized and approved for issuance under the 2012 LTIP, subject to certain adjustments. This number of shares is subject to appropriate adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, stock dividend, stock split or reverse stock split, cash dividend, property dividend, combination or exchange of shares, repurchase of shares, change in corporate structure or any similar corporate event or transaction. This number of shares may also increase due to the termination of an award granted under the 2012 LTIP, or under the Company’s Prior Plans (as defined below), by expiration, forfeiture, cancellation or otherwise without the issuance of the shares of common stock. Approximately 2.6 million shares were available for issuance under the 2012 LTIP as of December 31, 2014.

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

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

Prior to December 23, 2010, all options granted to employees were granted under the C&J Energy Services, Inc. 2006 Stock Option Plan (the “2006 Plan” and, together with the 2010 Plan, the “Prior Plans”). On December 23, 2010, the 2006 Plan was amended to provide, among other things, that (i) no additional awards would be granted under the 2006 Plan, (ii) all awards outstanding under the 2006 Plan would continue to be subject to the terms of the 2006 Plan and the

 

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applicable award agreement, and (iii) all unvested options under the 2006 Plan would immediately vest and become exercisable in connection with the completion of a private placement of common stock that occurred in December 2010. On May 29, 2012, the 2006 Plan was further amended to provide, among other things, that if and to the extent an award originally granted pursuant to the 2006 Plan is terminated by expiration, forfeiture, cancellation or otherwise without the issuance of shares of common stock, any and all shares of common stock associated with such award shall become available to be granted pursuant to a new award under the terms of the 2012 LTIP.

Stock Options

The fair value of each option award granted under the 2012 LTIP and the Prior Plans is estimated on the date of grant using the Black-Scholes option-pricing model. Due to the Company’s lack of historical volume of option activity, the expected term of options granted is derived using the “plain vanilla” method. In addition, expected volatilities have been based on comparable public company data, with consideration given to the Company’s limited historical data. The Company makes estimates with respect to employee termination and forfeiture rates of the options within the valuation model. The risk-free rate is based on the approximate U.S. Treasury yield rate in effect at the time of grant. For options granted prior to the Company’s initial public offering (“IPO”), which closed on August 3, 2011, the calculation of the Company’s stock price involved the use of different valuation techniques, including a combination of an income and/or market approach. Determination of the fair value was a matter of judgment and often involved the use of significant estimates and assumptions.

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

 

     Year Ended Decemer 31,
2012

Expected volatility

   65% - 75%

Expected dividends

   None

Exercise price

   $16.88 - $18.89

Expected term (in years)

   6

Risk-free rate

   0.9% - 1.4%

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

 

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

 

     Shares      Weighted
Average
Exercise Price
     Weighted
Average
Remaining
Contractual
Life
     Aggregate
Intrinsic
Value
 
     (in thousands)             (in years)      (in thousands)  

Outstanding at January 1, 2014

     5,283       $ 11.69         6.36       $ 65,351   

Granted

     —           —           

Exercised

     (159      5.23         

Forfeited

     (57      29.00         
  

 

 

    

 

 

    

 

 

    

 

 

 

Outstanding at December 31, 2014

  5,067    $ 11.70      5.40    $ 21,395   
  

 

 

    

 

 

    

 

 

    

 

 

 

Exercisable at December 31, 2014

  5,024    $ 11.65      5.38    $ 21,395   
  

 

 

    

 

 

    

 

 

    

 

 

 

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

Restricted Stock

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

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

 

     Shares      Weighted
Average
Grant-Date
Fair Value
 
     (in thousands)         

Non-vested at January 1, 2014

     1,133       $ 21.63   

Granted

     798         24.65   

Forfeited

     (75      23.14   

Vested

     (479      21.39   
  

 

 

    

 

 

 

Non-vested at December 31, 2014

  1,377    $ 23.39   
  

 

 

    

 

 

 

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

 

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As of December 31, 2014, the Company had 6.4 million stock options and shares of restricted stock outstanding to employees and non-employee directors, 1.0 million of which were issued under the 2006 Plan, 4.0 million were issued under the 2010 Plan and the remaining 1.4 million were issued under the 2012 Plan. As of December 31, 2013, the Company had 6.4 million of stock options and shares of restricted stock outstanding to employees and non-employee directors, 1.1 million of which were issued under the 2006 Plan, 4.1 million were issued under the 2010 Plan and the remaining 1.2 million were issued under the 2012 Plan.

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

Note 7 – Related Party Transactions

The Company obtains trucking and crane services on an arm’s length basis from certain vendors affiliated with two of its executive officers. For the years ended December 31, 2014, 2013 and 2012, purchases from these vendors totaled $7.4 million, $3.7 million and $2.6 million, respectively. Amounts payable to these vendors at December 31, 2014 and 2013 were $0.9 million and $0.1 million, respectively.

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

The Company obtains office space, equipment rentals, tool repair services and other supplies from vendors affiliated with several employees. For the years ended December 31, 2014, 2013 and 2012, purchases from these vendors were $1.0 million, $1.7 million and $1.3 million, respectively.

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

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

Note 8 – Business Concentrations

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. Concentrations of credit risk with respect to accounts receivable are limited because the Company performs credit evaluations, sets credit limits, and monitors the payment patterns of its customers. Cash balances on deposits with financial institutions, at times, may exceed federally insured limits. The Company regularly monitors the institutions’ financial condition.

The Company’s top ten customers accounted for approximately 51.1%, 64.6% and 81.0% of the Company’s consolidated revenue for the years ended December 31, 2014, 2013 and 2012, respectively. For the year ended December 31, 2014, revenue from two customers individually represented 16.4% and 9.6% of the Company’s consolidated revenue. For the year ended December 31, 2013, revenue from two customers individually represented 19.5% and 13.1% of the Company’s consolidated revenue. For the year ended December 31, 2012, revenue from three customers individually

 

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represented 19.1%, 15.6% and 12.9% of the Company’s consolidated revenue. Other than those listed above, no other customer accounted for 10% or more of the Company’s consolidated revenue in 2014, 2013 or 2012. Revenue was earned from each of these customers within the Company’s Stimulation and Well Intervention Services and Wireline Services segments.

Note 9 - Commitments and Contingencies

Environmental

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

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

Litigation

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

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

Service Equipment and Other Capital Expenditures

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

Inventory and Materials

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

 

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Operating Leases

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

Lease expense under all operating leases totaled $14.0 million $14.6 million and $12.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014, the future minimum lease payments under non-cancelable operating leases were as follows (in thousands):

 

Years Ending December 31,

      

2015

   $ 7,760   

2016

     5,318   

2017

     3,308   

2018

     2,479   

2019

     1,648   

Thereafter

     5,474   
  

 

 

 
$ 25,987   
  

 

 

 

Note 10 – Employee Benefit Plans

The Company maintains two contributory profit sharing plans under a 401(k) arrangement which covers all employees meeting certain eligibility requirements. Eligible employees can make annual contributions to the plans up to the maximum amount allowed by current federal regulations. The Company matches dollar for dollar all contributions made by eligible employees up to 4% of their gross salary. The Company’s 401(k) contributions for the years ended December 31, 2014, 2013 and 2012 totaled $2.3 million, $1.9 million and $1.0 million, respectively.

Note 11 - Segment Information

In accordance with FASB ASC 280 Segment Reporting, the Company routinely evaluates whether it has separate operating and reportable segments. The Company has determined that it operates in three reportable segments: Stimulation and Well Intervention Services, Wireline Services and Equipment Manufacturing. This determination is made based on the following factors: (1) the Company’s chief operating decision maker is currently managing each segment as a separate business and evaluating the performance of each segment and making resource allocation decisions distinctly and expects to do so for the foreseeable future, and (2) discrete financial information for each segment is available. The following is a brief description of the Company’s three segments:

Stimulation and Well Intervention Services. This segment has two related service lines providing hydraulic fracturing services and coiled tubing and other well stimulation services. The Company’s other well stimulation services primarily include nitrogen, pressure pumping and thru-tubing services. Additionally, with the development of a specialty chemicals business and strategic acquisitions during 2013, the Company now blends and supplies specialty chemicals for completion and production services, and also manufactures and provides downhole tools and related directional drilling technology and data acquisition and control systems, all of which are currently considered part of the Company’s other well stimulation services.

Wireline Services. This segment provides cased-hole wireline, pumpdown and other complementary services, including logging, perforating, pipe recovery and pressure testing services. The results of Tiger since May 30, 2014, which is the date of the Company’s acquisition of Tiger, have been included in the Company’s consolidated financial

 

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statements and reflected in this segment. See “Note 3 – Mergers and Acquisitions” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) in Item 2 of this Form 10-K for further discussion regarding the Tiger Acquisition.

Equipment Manufacturing. This 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 the Company’s Stimulation and Well Intervention Services and Wireline Services segments.

The following tables set forth certain financial information with respect to the Company’s reportable segments. Included in “Corporate and Other” are intersegment eliminations and costs associated with activities of a general corporate nature.

 

     Stimulation &
Well Intervention
Services
     Wireline
Services
     Equipment
Manufacturing
     Corporate
and Other
    Total  
     (in thousands)  

Year ended December 31, 2014

             

Revenue from external customers

   $ 1,186,592       $ 408,486       $ 11,800       $ 1,066      $ 1,607,944   

Inter-segment revenues

     579         —           128,133         (128,712     —     

Adjusted EBITDA

     181,527         135,803         31,221         (95,042     253,509   

Depreciation and amortization

     66,459         38,849         1,924         913        108,145   

Operating income (loss)

     115,761         96,732         29,286         (118,035     123,744   

Capital expenditures

     244,245         78,951         5,011         (12,489     315,718   

As of December 31, 2014

             

Total assets

   $ 946,151       $ 518,817       $ 132,795       $ 14,983      $ 1,612,746   

Goodwill

     69,109         146,126         4,718         —          219,953   

Year ended December 31, 2013

             

Revenue from external customers

   $ 783,408       $ 278,820       $ 8,094       $ —        $ 1,070,322   

Inter-segment revenues

     437         4         55,969         (56,410     —     

Adjusted EBITDA

     166,277         81,640         7,017         (64,260     190,674   

Depreciation and amortization

     47,446         26,359         1,670         (772     74,703   

Operating income (loss)

     118,777         54,585         5,342         (64,489     114,215   

Capital expenditures

     118,539         41,166         1,044         (2,762     157,987   

As of December 31, 2013

             

Total assets

   $ 654,360       $ 401,227       $ 80,807       $ (4,094   $ 1,132,300   

Goodwill

     69,625         131,455         4,718         —          205,798   

Year ended December 31, 2012

             

Revenue from external customers

   $ 940,258       $ 130,125       $ 41,118       $ —        $ 1,111,501   

Inter-segment revenues

     109         —           68,869         (68,978     —     

Adjusted EBITDA

     338,286         37,283         15,748         (54,605     336,712   

Depreciation and amortization

     32,738         11,813         2,303         58        46,912   

Operating income (loss)

     304,985         25,200         13,444         (61,099     282,530   

Capital expenditures

     154,977         28,512         7,529         (8,839     182,179   

As of December 31, 2012

             

Total assets

   $ 588,413       $ 370,955       $ 76,604       $ (23,215   $ 1,012,757   

Goodwill

     60,339         131,455         4,718         —          196,512   

 

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Revenue by service line for the Stimulation and Well Intervention Services segment for the years ended December 31, 2014, 2013 and 2012 was as follows (in thousands):

 

     Years Ended December 31,  

Service Line

   2014      2013      2012  

Hydraulic fracturing

   $ 984,971       $ 626,297       $ 784,923   

Coiled tubing and other well stimulation

     201,621         157,111         155,335   
  

 

 

    

 

 

    

 

 

 

Total revenue

$ 1,186,592    $ 783,408    $ 940,258   
  

 

 

    

 

 

    

 

 

 

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

As required under Item 10(e) of Regulation S-K of the Securities Exchange Act of 1934, as amended, included below is a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, to net income, which is the nearest comparable U.S. GAAP financial measure (in thousands).

 

     Years Ended December 31,  
     2014      2013      2012  

Adjusted EBITDA

   $ 253,509       $ 190,674       $ 336,712   

Interest expense, net

     (9,840      (6,550      (4,996

Income tax expense

     (45,679      (41,313      (95,079

Depreciation and amortization

     (108,145      (74,703      (46,912

Gain (loss) on disposal of assets

     17         (527      (692

Transaction costs

     (20,159      (306      (833

Legal settlement

     —           —           (5,850

Insurance settlement

     (880      —           —     

Inventory write-down

     —           (870      —     
  

 

 

    

 

 

    

 

 

 

Net income

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

 

 

    

 

 

    

 

 

 

 

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Note 12 – Quarterly Financial Data (unaudited)

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

 

     Quarters Ended  
     March 2014      June 2014      September
2014
     December
2014
 

Revenue

   $ 316,537       $ 367,921       $ 439,978       $ 483,508   

Operating income

     20,908         20,060         42,011         40,765   

Income before income taxes

     19,325         18,077         39,439         37,661   

Net income

     11,588         11,108         23,816         22,311   

Net income per common share:

           

Basic

   $ 0.22       $ 0.21       $ 0.44       $ 0.41   

Diluted

   $ 0.21       $ 0.20       $ 0.42       $ 0.40   

 

     Quarters Ended  
     March 2013      June 2013      September
2013
     December
2013
 

Revenue

   $ 276,051       $ 266,956       $ 261,931       $ 265,384   

Operating income

     40,418         34,855         23,459         15,483   

Income before income taxes

     38,824         33,236         21,921         13,737   

Net income

     25,143         20,847         13,125         7,290   

Net income per common share:

           

Basic

   $ 0.48       $ 0.39       $ 0.25       $ 0.14   

Diluted

   $ 0.46       $ 0.38       $ 0.24       $ 0.13   

Note 13 – Pending Merger with the Completion and Production Services Business of Nabors Industries, Ltd.

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

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

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

C&J currently expects the closing of the merger to occur in late March 2015, following receipt of stockholder approval at the special meeting of stockholders scheduled for March 20, 2015, and subject to the satisfaction of other customary closing items. There can be no assurance as to whether or when the closing will occur.

 

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

None.

 

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) under the Exchange Act, the Company has evaluated, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) and internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) as of the end of the period covered by this Form 10-K. The Company’s disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to its management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, the Company’s principal executive officer and principal financial officer concluded that its disclosure controls and procedures were effective as of December 31, 2014.