C&J Energy Services 10-K 2013 FY Annual report

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, 2013.

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.)

10375 Richmond Avenue, Suite 1910

Houston, Texas 77042

(Address of principal executive offices)

(713) 260-9900

(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 28, 2013 (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 $702.0 million.

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at February 21, 2014, was 55,398,749.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for its 2014 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2013, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		4
Item 1A.	Risk Factors		18
Item 1B.	Unresolved Staff Comments		28
Item 2.	Properties		29
Item 3.	Legal Proceedings		30
Item 4.	Mine Safety Disclosures		30
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		31
Item 6.	Selected Financial Data		33
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		53
Item 8.	Financial Statements and Supplementary Data		55
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		86
Item 9A.	Controls and Procedures		86
Item 9B.	Other Information		86
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		87
Item 11.	Executive Compensation		87
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		87
Item 13.	Certain Relationships and Related Transactions, and Director Independence		88
Item 14.	Principal Accounting Fees and Services		88
PART IV
Item 15.	Exhibits, Financial Statement Schedules		89
	Signatures		93

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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 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 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; and

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

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 impacts 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 impacts demand for our services;

• 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;

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

• risks associated with business growth outpacing the capabilities of our infrastructure;

• adverse weather conditions in oil or gas producing regions;

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

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

• risks associated with 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;

• 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; and

• 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 assets sales or equity issuances should we need to raise funds through such methods.

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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., a Delaware corporation, was founded in Texas in 1997. On July 29, 2011, our common stock began trading on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” 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, wireline and other complementary services with a focus on complex, technically demanding well completions. These services are provided to oil and natural gas exploration and production companies throughout the United States. In addition to our core service offerings, we manufacture, repair and refurbish equipment and provide oilfield parts and supplies for third-party companies in the energy services industry, as well as to fulfill our internal needs.

Strategic Initiatives and Growth Strategy

Expansion of Core Service Lines

During 2013, we focused 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 2013 we added capacity to our core service lines as we expanded our customer base through increased sales and marketing efforts and introduced our hydraulic fracturing and coiled tubing operations to new markets. With respect to our hydraulic fracturing operations, we successfully deployed an additional 64,000 hydraulic horsepower capacity during the year while managing our increasing spot market exposure with the expiration of all but one of our legacy term contracts. In addition to expanding our customer base, we extended our geographic reach into the Mid-Continent region with the deployment of 32,000 hydraulic horsepower capacity in Oklahoma. In response to the increase in demand from new and existing customers that we experienced early in the fourth quarter of 2013, and believing that activity levels will improve during 2014, we committed to add 20,000 new horsepower during the first half of 2014.

We also grew our coiled tubing and wireline businesses, deploying six new coiled tubing units and six new wireline units during the year. The roll-out of our larger-diameter coiled tubing units was met with strong demand, as we added new equipment and redeployed modified units over the second half of 2013. Through our wireline business we also increased our pumpdown operations with the deployment of fourteen pumpdown units. We have successfully leveraged the broader customer base and geographic reach of our wireline business to introduce our coiled tubing operations to new customers as well as into new areas. During 2013, we added coiled tubing services to our existing wireline and pressure pumping operations in the Marcellus Shale and strengthened the presence of our coiled tubing, wireline and pressure pumping operations in the Eagle Ford and Bakken Shales and the Permian Basin. In late December, we purchased three additional high-capacity coiled tubing units and ancillary equipment for deployment during the first quarter of 2014, and we are also deploying two new wireline units and four new pumpdown units during the first quarter of 2014.

We are confident in the strength of our core service lines, and we intend to continue increasing market share by strengthening our presence within our existing geographic footprint and concentrating on targeted expansion of our hydraulic fracturing and coiled tubing operations into areas in which our wireline business already has a strong presence.

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With respect to our international expansion efforts, during 2013 we established a presence in the Middle East and positioned ourselves to capitalize on opportunities that may arise in the region. 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. During 2014, we expect to commence construction of an operational facility in Dubai to support our anticipated future Middle East operations. We were recently awarded our first contract to provide coiled tubing services on a trial basis in Saudi Arabia and we are shipping equipment to the region with operations expected to commence during the second quarter of 2014. Due to the size of this first project and the additional costs associated with establishing operations overseas, we do not expect to generate financial returns during this initial phase. Additionally, there is no guarantee that we will be able to obtain additional work with this customer beyond this provisional contract. However, we believe that this is a valuable opportunity to demonstrate our services outside of the United States. We are optimistic that our efforts can lead to a long-term relationship as we strive to establish ourselves as a provider of multiple services to 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.

Expansion of Service Offerings

During 2013, we invested in a number of strategic initiatives designed to expand our business through vertical integration, service line diversification and technological advancement. The support of these initiatives led to an increase in capital expenditures and costs during 2013. We expect that our expenses will continue to increase over the course of 2014 as we continue to invest in the further development of these projects. Our strategic initiatives did not contribute significant third-party revenue during 2013, and we do not expect that any will contribute meaningful third-party revenue during 2014. However, we believe that these investments will yield significant financial returns, as well as meaningful cost savings to us, over the long term. Our key strategic initiatives in 2013 included the following:

• We organically developed 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. We are also actively marketing this business to third-party customers. 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.

• We expanded our portfolio of products and services through two small acquisitions of private companies that complement and enhance our existing service lines. In April 2013, we acquired a provider of directional drilling technology and related downhole tools. As a result of this acquisition, we will begin leasing premium drilling motors to our customers during 2014, and we are in the early stages of development with additional related products. In December 2013, we acquired a manufacturer of data control instruments that are used in our hydraulic fracturing operations. In addition to achieving cost savings through intercompany purchases, we also intend to sell these products to third-party energy services companies. We believe that both of these businesses have significant growth potential and we intend to continue investing in their development.

• We advanced our Research and Technology capabilities, including through investing in a new Research and Technology center and assembling a team of engineers and support staff. Our efforts are currently focused on developing innovative, fit-for-purpose solutions that will enhance our core service lines, increase completion efficiencies and add value for our customers. We intend to introduce several new products during 2014, which we expect to provide cost savings to our operations.

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Our principal executive offices are currently located at 10375 Richmond Avenue, Suite 1910, Houston, Texas 77042 and our main telephone number at that address is (713) 260-9900. 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 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.

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 hydraulic fracturing, coiled tubing and other well stimulation services, with a focus on complex, technically demanding well completions.

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 hydraulic fracturing business currently consists of more than 300,000 total horsepower capacity. We deployed 64,000 new horsepower capacity during 2013, with 32,000 horsepower deployed in Oklahoma as we extended the geographic reach of this service line into the Mid-Continent region. In response to the increase in demand from new and existing customers that we experienced early in the fourth quarter of 2013, and believing that activity levels would improve during 2014, we committed to add 20,000 new horsepower during the first half of 2014.

Our hydraulic fracturing operations contributed $626.3 million of revenue and we completed 6,159 fracturing stages for the year ended December 31, 2013.

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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Our coiled tubing business currently consists of 27 coiled tubing units. During 2013, we deployed six new extended-reach larger-diameter coiled tubing units in response to an industry trend towards such higher-specification equipment, and we also modified certain of our existing coiled tubing equipment to meet customer demand. In December 2013, we purchased three additional high-capacity coiled tubing units and ancillary equipment. Two of these units were placed into service in mid-February, and we expect to deploy the other unit during the first quarter of 2014.

Our coiled tubing operations contributed $140.4 million of revenue and we completed 4,035 coiled tubing jobs for the year ended December 31, 2013.

Our other well stimulation services primarily include nitrogen, pressure pumping and thru-tubing services. Additionally, with the development of our specialty chemicals business and our strategic acquisitions during 2013, we now provide specialty chemicals for completion and production services, as well as downhole tools and related directional drilling technology and data control systems. 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 $16.7 million of revenue for the year ended December 31, 2013, with the substantial majority generated from our nitrogen, pressure pumping and thru-tubing services.

Wireline Services

We commenced our Wireline Services segment with the acquisition of Casedhole Solutions on June 7, 2012. See “Note 3 – Acquisitions” in Part II, Item 8 “Financial Statements and Supplementary Data” for further discussion regarding the Casedhole Solutions acquisition. Our Wireline Services segment provides cased-hole wireline and other complementary services, including logging, perforating, pipe recovery, pressure testing and pumpdown services, which are critical throughout a well’s life cycle.

Our Wireline Services segment currently consists of 69 wireline units and 33 pumpdown units, as well as pressure control and other ancillary equipment. We deployed six new wireline units and fourteen pumpdown units during 2013. We currently intend to deploy an additional two new wireline units and four new pumpdown units during the first quarter of 2014.

Our Wireline Services segment contributed $278.8 million of revenue for the year ended December 31, 2013.

Equipment Manufacturing

We commenced our Equipment Manufacturing segment with the acquisition of Total E&S, Inc. in April 2011. Our Equipment Manufacturing segment constructs oilfield equipment, including hydraulic fracturing pumps, coiled tubing units and pressure pumping units for third-party customers in the energy services industry, as well as for our Stimulation and Well Intervention Services and Wireline Services segments. This segment also provides equipment repair and refurbishment services and oilfield parts and supplies to the energy services industry, and to meet our own internal needs.

Our Equipment Manufacturing segment contributed $8.1 million in third-party revenue for the year ended December 31, 2013.

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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 and the Eagle Ford, Bakken and Marcellus Shales. During the three year period ended December 31, 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 2013, we focused on expanding our geographic reach, both domestically and internationally. With respect to our international expansion efforts, during 2013 we established a presence in the Middle East, which included opening our first international office in Dubai. We were recently awarded our first contract to provide coiled tubing services on a trial basis in Saudi Arabia and we are shipping equipment to the region with operations expected to commence during the second quarter of 2014. Due to the size of this first project and the additional costs associated with establishing operations overseas, we do not expect to generate financial returns during this initial phase. Additionally, there is no guarantee that we will be able to obtain additional work with this customer beyond this provisional contract. However, we believe that this is a valuable opportunity to demonstrate our services outside of the United States. We are optimistic that our efforts can lead to a long-term relationship as we strive to establish ourselves as a provider of multiple services to 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 during the Christmas holiday, and activity sometimes slows during the latter part of the year as our customers exhaust their annual capital spending budgets. Additionally, our business has been in the past and may in the future be impacted during the winter months due to inclement weather as 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 geographical 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 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 allows us to successfully expand our customer base and better serve our existing customers.

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. This strategy has worked particularly well for growing our coiled tubing operations. During 2013 we added coiled tubing services to our existing wireline operations in the Marcellus Shale and strengthened the presence of our coiled tubing, wireline and pressure pumping operations in the Eagle Ford and Bakken Shales and the Permian Basin.

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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. We believe that our spot market work can serve as a valuable marketing tool as it allows us to introduce our hydraulic fracturing services to new customers. 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. We believe that we have the experience and resources to capitalize on these trends.

Customers

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 2013. 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 the spot market pricing experienced during 2013. 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, which increased our ability to work for new customers in the spot market. We are taking advantage of the opportunity to introduce our services to new customers and new markets. However, 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, thereby reducing overall customer concentration. 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 numerous independent and major oil and gas companies across the continental United States. However, given the significance of our hydraulic fracturing operations to us, our revenue, earnings and cash flows are substantially dependent upon a concentrated group of customers.

Our top ten customers accounted for approximately 64.6%, 81.0% and 92.7% of our consolidated revenue for the years ended December 31, 2013, 2012 and 2011, respectively. For the year ended December 31, 2013, revenue from two customers individually represented 19.5% and 13.1%, respectively, of our consolidated revenue. For the year ended December 31, 2012, revenue from three customers individually represented 19.1%, 15.6% and 12.9%, respectively, of our consolidated revenue. For the year ended December 31, 2011, revenue from five customers individually represented 23.1%, 18.2%, 15.9%, 13.2% and 10.4%, respectively, of our consolidated revenue. Other than those listed above, no other customer accounted for more than 10% of our consolidated revenue in 2013, 2012 or 2011, respectively. If we were to lose any material customer, we believe that in the current market environment we would be able to redeploy our equipment with limited downtime. However, the loss of a material customer could have an adverse effect on our business until the equipment is redeployed at similar utilization levels.

The customers served through our equipment manufacturing business are primarily energy services companies. C&J historically has been, and continues to be, one of the top customers for this business and it did not generate a significant portion of our consolidated revenue for the years ended December 31, 2013, 2012 or 2011.

Competition and Demand for Our Services

The markets in which we provide our core service offerings are highly competitive. We provide these services across the continental United States and our competitors include many large and small

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energy service companies, including some of the largest integrated energy services companies. Our major competitors for our fracturing services include Halliburton, Schlumberger, Baker Hughes, 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 Gray.

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. We target high volume, high efficiency customers with service intensive, twenty-four hour work, which is where we believe we can differentiate our services from our competitors.

The demand for our services fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven primarily by the supply of, and demand for, oil and natural gas. Generally, as supply of the 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. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work. 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 may experience a more rapid decline in demand for well maintenance services compared with demand for other types of energy services. Further, in a low commodity price environment, fewer well service rigs are needed for completions, as these activities are generally associated with drilling activity.

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.) and National Oilwell Varco, Inc. For our well servicing and coiled tubing and other well stimulation products, our major competitors are National Oilwell Varco, Inc. and Stewart & Stevenson. 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, 2013, we purchased 5% or more of the materials and/or products used in our Stimulation and Well Intervention Services and Wireline Services segments from each of our equipment manufacturing business, our specialty chemicals business and a third-party sand provider. We are not dependent on any single supply

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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.

For information regarding our related-party suppliers, please see “Transactions with Related Persons – Related Person Transactions” in our definitive proxy statement for the 2014 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, 2013.

Safety

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 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.

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.

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.

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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. 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 maintain insurance for both property damage and business interruption relating to catastrophic events. Business interruption coverage covers lost profits and other costs incurred. Non-refundable insurance recoveries received in excess of the net book value of damaged assets, clean-up and demolition costs, and post-event costs are recognized as income in the period received.

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.

Employees

As of February 21, 2014, we had 2,609 employees. We increased our overall headcount by approximately 33% over the course of 2013 to support the growth of our business. We anticipate hiring additional employees as we continue to execute our growth strategy. Subject to local market conditions,

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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 possession and handling of 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. The oil and gas industry is subject to environmental regulation pursuant to local, state and federal legislation.

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

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

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

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

Environmental Matters

Our operations are subject to stringent and complex federal, state and local environmental and occupational, health and safety laws and regulations, including those governing the release and/or discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, injunctions prohibiting some or all of our operations, assessment of administrative and civil penalties, and even criminal prosecution. We believe that we are in substantial compliance with applicable environmental laws and regulations. Further, we do

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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 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.

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Water Discharges

The Federal Water Pollution Control Act, as amended (the “Clean Water Act”), and applicable state laws 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. Spill prevention, control and countermeasure requirements 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, as amended, 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 Oil Pollution Act, 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, as amended (“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. At the same time there are a number of governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.

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 the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel. 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.

In addition, certain governmental reviews are 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 in late 2014. 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 by late 2014. 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.

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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 and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as certain watersheds. Texas has adopted legislation that requires the public disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and to the public. This legislation and any implementing regulations could increase our costs of compliance and doing business. Moreover, the availability of information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Disclosure of our proprietary chemical formulas to third parties or to the public, even if inadvertent, could diminish the value of those formulas and could result in competitive harm to us.

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.

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 facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose generally applicable limitations on air emissions and require adherence to maintenance, work practice, reporting and recordkeeping, and other requirements. Many of these regulatory requirements, including “New Source Performance Standards” (“NSPS”) and “Maximum Achievable Control Technology” (“MACT”) standards are expected to be made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of substantial administrative, civil and even criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional expenses and operational delays.

In August 2012, the EPA adopted new rules that subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the NSPS and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The rules also include NSPS standards

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for completions of hydraulically fractured gas wells. These standards require use of the reduced emission completion (“REC”) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the regulations under NESHAPS include MACT standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. 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. In December 2009, the EPA published its findings 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 construction 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. 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 planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any new federal, regional or state restrictions on emissions of carbon dioxide or other GHGs that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such restrictions could potentially make our customers’ products more expensive and thus reduce demand for them, which 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, as amended (“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. You should carefully consider each of the following risk factors and all of the other information set forth in this Form 10-K and our other reports filed with the SEC, and the documents and other information incorporated by reference herein and therein, before investing in our shares. 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 us. 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 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 current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices;

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

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

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

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

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

• regulation of drilling activity;

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

• available pipeline and other transportation capacity;

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• 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 and may impact drilling or completion activity. 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.

There is significant potential for excess capacity in our industry, which could adversely affect our business and operating results.

Significant increases in overall market capacity could cause our competitors to lower their rates and lead to a decrease in rates in the energy services industry generally. Natural gas prices declined sharply in 2009 and remained depressed through 2013, 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, where capacity currently exceeds demand. 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. Historically, most of our hydraulic fracturing revenue was generated by work provided under our six legacy term contracts, which had minimum utilization requirements and favorable pricing terms relative to the current spot market pricing. Over the course of 2013, all but one of our legacy long-term contracts expired and the remaining contract is scheduled to expire at the end of February 2014. With our increased spot market exposure, we are now subject, among other things, to the pricing conditions of the markets in which we provide our services.

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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.

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 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 64.6%, 81.0% and 92.7% of our consolidated revenue for the years ended December 31, 2013, 2012 and 2011, 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 or decides not to continue to use our services, revenue could decline and our operating results and financial condition could be harmed.

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;

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• 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. 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. 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.

In addition, certain governmental reviews are 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 in late 2014. 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 by late 2014. 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 and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as certain watersheds. Texas has adopted legislation that requires the public disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and to the public. This legislation and any implementing regulations could increase our costs of compliance and doing business. Moreover, the availability of information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Disclosure of our proprietary chemical formulas to third parties or to the public, even if inadvertent, could diminish.

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,

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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 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, 2013, our net income increased from $1.1 million to $66.4 million and our revenue increased from $62.4 million to $1.1 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. The 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.

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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. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. 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. The successful execution of our growth strategy depends on our ability to raise additional capital as needed. 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 to sustain or increase our current level. 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 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 $400.0 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

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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 maintenance capital expenditures.

A breach of any of these covenants could result in a default under our Credit Facility. Upon the occurrence of an event of default under our Credit Facility, 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 our Credit Facility 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 our Credit Facility. If the lenders under our Credit Facility 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.

In December 2009, the EPA published its findings 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 Clean Air Act including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction 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 planned 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.

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 potentially make our customers’ products more expensive and thus reduce demand for them, 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.

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

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

• issuance of administrative, civil and criminal penalties;

• modification, denial or revocation of permits or other authorizations;

• imposition of limitations on our operations; and

• performance of site investigatory, remedial or other corrective actions.

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

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

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

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

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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 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. We were recently awarded our first contract to provide coiled tubing services on a trial basis in Saudi Arabia and we are shipping equipment to the region with operations expected to commence during the second quarter of 2014. Risks associated with operations in foreign areas, such as the Middle East, include, but are not limited to:

• expropriation, confiscation or nationalization of assets;

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• renegotiation or nullification of existing contracts;

• foreign exchange limitations;

• foreign currency fluctuations;

• foreign taxation;

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

• changing political conditions;

• changing foreign and domestic monetary policies;

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

• regional economic downturns.

Risks Related to Our Common 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 (2013 low of $17.45 per share; 2013 high of $25.35 per share), 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 21, 2014, we had 55,398,749 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

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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 currently located at 10375 Richmond Avenue, Suite 1910, Houston, Texas 77042, where we lease 29,385 square feet of general office space pursuant to a lease agreement expiring on January 31, 2017. On February 21, 2013, we entered into a “build-to-suit” lease agreement with an option to purchase providing for the immediate construction of a 125,000 square feet office park at 3802 Rogerdale Road, Houston, Texas, 77042. This facility will serve as our new corporate headquarters. We expect to move into our new corporate facility on or before April, 1 2014. We believe that we will be able to enter into sublease agreements for our current office space for the remainder of our original lease term.

We own or lease facilities and administrative offices throughout the geographic regions in which we operate. As of February 21, 2014, 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	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 Rd. 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 Dr. Midland, TX	Administrative offices, maintenance shop, equipment yard	7 acres, 22,124 sq. ft. building space	Owned	—	Wireline Services
Lot 1, Block 3 Section 1 San Angelo, TX	Administrative offices, maintenance shop, equipment yard	20 acres, 20,237 sq. ft. building space (under construction)	Owned	—	Wireline Services
4700 Commerce St. 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
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

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Location	Type of Facility	Size	Lease or Owned	Expiration of Lease	Primary Business Use
Plot No. S40320 & S40321 Dubai, UAE	Administrative offices, maintenance shop, equipment yard	14 acres, 104,775 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 Dr. 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 sq.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
34011 Sunset Lane Brookshire, TX	Administrative offices, chemical blending & distribution facility	8 acres, 12,500 sq. ft. building space	Owned	—	Specialty Chemicals

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

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

Item 3. Legal Proceedings

We are subject to various legal proceedings and claims incidental to or arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or results of operations. We will continue to evaluate proceedings and claims involving us on a quarter-by-quarter basis and will establish and adjust any reserves as appropriate to reflect our assessment of the then-current status of the matters.

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 21, 2014, we had 55,398,749 shares of common stock issued and outstanding, held by approximately 24 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, 2012
Quarter ended March 31, 2012		23.11		16.05
Quarter ended June 30, 2012		19.94		16.15
Quarter ended September 30, 2012		22.66		17.37
Quarter ended December 31, 2012		22.09		17.80
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
Period from January 1, 2014 to February 21, 2014		25.40		20.26

On February 21, 2014, the last reported sales price of our common stock on the NYSE was $24.26 per share.

We have not declared or paid any cash dividends on our common stock. We currently intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. Payments of dividends, if any, will be at the discretion of our Board and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our Board. Additionally, covenants contained in our 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, 2013 and February 21, 2014, 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, 2013 (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 21, 2014, 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		2,415		23.69		—		—
March 1—March 31		—		—		—		—
April 1—April 30		—		—		—		—
May 1—May 31		—		—		—		—
June 1—June 30		62,300		18.98		—		—
July 1—July 31		1,086		20.56		—		—
August 1—August 31		6,157		21.44		—		—
September 1—September 30		359		21.92		—		—
October 1—October 31		265		20.52		—		—
November 1—November 30		1,042		23.49		—		—
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,
	2013		2012		2011		2010		2009
	(In thousands except per share amounts)
Revenue	$	1,070,322	$	1,111,501	$	758,454	$	244,157	$	67,030
Net income (loss)		66,405		182,350		161,979		32,272		(2,430	)
Net income (loss) per common share
Basic		1.25		3.51		3.28		0.70		(0.05	)
Diluted		1.20		3.37		3.19		0.67		(0.05	)
Total assets		1,132,300		1,012,757		537,849		226,088		150,231
Long-term debt and capital lease obligations, excluding current portion		164,205		173,705		—		44,817		60,668

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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

We are an independent provider of premium hydraulic fracturing, coiled tubing, wireline and other complementary services with a focus on complex, technically demanding well completions. These services are provided to oil and natural gas exploration and production companies throughout the United States. In addition to these core service offerings, we manufacture, repair and refurbish equipment and provide oilfield parts and supplies for third-party companies in the energy services industry, as well as to fulfill our internal needs.

We currently operate in three reportable segments: Stimulation and Well Intervention Services; Wireline Services; and Equipment Manufacturing. Our three segments are described in more detail under “Our Operating Segments.” For additional financial information about our segments, including revenue from external customers and total assets by segment, see “Note 11 – Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data.”

Strategic Initiatives and Growth Strategy

Expansion of Core Service Lines

During 2013, we focused 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 2013 we added capacity to our core service lines as we expanded our customer base through increased sales and marketing efforts and introduced our hydraulic fracturing and coiled tubing operations to new markets. With respect to our hydraulic fracturing operations, we successfully deployed an additional 64,000 hydraulic horsepower capacity during the year while managing our increasing spot market exposure with the expiration of all but one of our legacy term contracts. In addition to expanding our customer base, we extended our geographic reach into the Mid-Continent region with the deployment of 32,000 hydraulic horsepower capacity in Oklahoma. In response to the increase in demand from new and existing customers that we experienced early in the fourth quarter of 2013, and believing that activity levels will improve during 2014, we committed to add 20,000 new horsepower during the first half of 2014.

We also grew our coiled tubing and wireline businesses, deploying six new coiled tubing units and six new wireline units during the year. The roll-out of our larger-diameter coiled tubing units was met with strong demand, as we added new equipment and redeployed modified units over the second half of 2013. Through our wireline business we also increased our pumpdown operations with the deployment of fourteen pumpdown units. We have successfully leveraged the broader customer base and geographic reach of our wireline business to introduce our coiled tubing operations to new customers as well as into new areas. During 2013, we added coiled tubing services to our existing wireline and pressure pumping operations in the Marcellus Shale and strengthened the presence of our coiled tubing, wireline and pressure pumping operations in the Eagle Ford and Bakken Shales and the Permian Basin. In late

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December, we purchased three additional high-capacity coiled tubing units and ancillary equipment for deployment during the first quarter of 2014, and we are also deploying two new wireline units and four new pumpdown units during the first quarter of 2014.

We are confident in the strength of our core service lines, and we intend to continue increasing market share by strengthening our presence within our existing geographic footprint and concentrating on targeted expansion of our hydraulic fracturing and coiled tubing operations into areas in which our wireline business already has a strong presence.

With respect to our international expansion efforts, during 2013 we established a presence in the Middle East and positioned ourselves to capitalize on opportunities that may arise in the region. 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. During 2014, we expect to commence construction of an operational facility in Dubai to support our anticipated future Middle East operations. We were recently awarded our first contract to provide coiled tubing services on a trial basis in Saudi Arabia and we are shipping equipment to the region with operations expected to commence during the second quarter of 2014. Due to the size of this first project and the additional costs associated with establishing operations overseas, we do not expect to generate financial returns during this initial phase. Additionally, there is no guarantee that we will be able to obtain additional work with this customer beyond this provisional contract. However, we believe that this is a valuable opportunity to demonstrate our services outside of the United States. We are optimistic that our efforts can lead to a long-term relationship as we strive to establish ourselves as a provider of multiple services to 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.

Expansion of Service Offerings

During 2013 we invested in a number of strategic initiatives designed to expand our business through vertical integration, service line diversification and technological advancement. The support of these initiatives led to an increase in capital expenditures and additional costs during 2013. We expect that our expenses will continue to increase over the course of 2014 as we continue to invest in the further development of these projects. Our strategic initiatives did not contribute significant third-party revenue during 2013, and we do not expect that any will contribute meaningful third-party revenue during 2014. However, we believe that these investments will yield significant financial returns, as well as meaningful cost savings to us, over the long term. Our key strategic initiatives in 2013 included the following:

• We organically developed 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. We are also actively marketing this business to third-party customers. 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.

• We expanded our portfolio of products and services through two small acquisitions of private companies that complement and enhance our existing service lines. In April 2013, we acquired a provider of directional drilling technology and related downhole tools. As a result of this acquisition, we will begin leasing premium drilling motors to our customers during 2014, and we are in the early stages of development with additional related products. In December 2013, we acquired a manufacturer of data control instruments that are used in our hydraulic fracturing operations. In addition to achieving cost savings through intercompany purchases, we also intend to sell these products to third-party energy services companies. We believe that both of these businesses have significant growth potential and we intend to continue investing in their development.

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• We advanced our Research and Technology capabilities, including through investing in a new Research and Technology center and assembling a team of engineers and support staff. Our efforts are currently focused on developing innovative, fit-for-purpose solutions that will enhance our core service offerings, increase completion efficiencies and add value for our customer. We intend to introduce several new products during 2014, which we expect to provide cost savings to our operations.

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

Stimulation and Well Intervention Services Segment

Our Stimulation and Well Intervention Services segment provides hydraulic fracturing, coiled tubing and other well stimulation services, with a focus on complex, technically demanding well completions.

Hydraulic Fracturing Services. Our hydraulic fracturing business currently consists of more than 300,000 total horsepower capacity. We deployed 64,000 new horsepower capacity during 2013, with 32,000 horsepower deployed in Oklahoma as we extended the geographic reach of this service line into the Mid-Continent region. In response to the increase in demand from new and existing customers that we experienced early in the fourth quarter of 2013, and believing that activity levels would improve during 2014, we committed to add 20,000 new horsepower during the first half of 2014. Entering 2014, we are encouraged by current activity levels across our asset base, even though pricing has remained flat and there is no guarantee that these activity levels will be sustained or improve.

Our hydraulic fracturing operations contributed $626.3 million, or 58.5%, to our consolidated revenue and we completed 6,159 fracturing stages during the year ended December 31, 2013, compared to $784.9 million of revenue and 6,243 fracturing stages for the previous year. The declines in revenue and stages performed year over year were due to our increased exposure to a highly competitive spot market, which resulted in lower utilization and pricing for our hydraulic fracturing services and led to a more varied job mix. Our exposure to the spot market increased significantly over the course of 2013 with the expiration of all but one of our legacy term contracts. As of December 31, 2013, we were providing services under one remaining term contract, which is scheduled to expire at the end of February 2014. However, we have been, and currently are, providing services to this contracted customer at reduced rates more consistent with spot market pricing. Although our 2013 financial results were negatively impacted by our increased spot market exposure, we expanded our customer base through increased sales and marketing efforts and we extended our geographic reach into the Mid-Continent region with the deployment of 32,000 hydraulic horsepower in Oklahoma early in the fourth quarter. We believe we have adjusted to our new operating environment and we remain focused on improving utilization through the expansion of our customer base and geographic presence.

During 2013, we provided hydraulic fracturing services pursuant to term contracts and pricing agreements or on a spot market basis. Historically, most of our hydraulic fracturing services were performed under six legacy term contracts, which had minimum utilization requirements and favorable pricing terms relative to the spot market pricing experienced during 2013. Over the course of 2013, all but one of our legacy term contracts expired, however, we were able to transition two of them into short-term

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pricing agreements. We also reduced the pricing terms of our remaining term contract to reflect rates more consistent with spot market pricing. 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. Under pricing agreements, our customers typically commit to targeted utilization levels 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 to then-current market rates upon the agreement of both parties. For the year ended December 31, 2013, we derived 36.6% of our consolidated revenue from hydraulic fracturing services performed under term contracts and pricing agreements.

Our exposure to the spot market increased significantly over the course of 2013 with the expiration of all but one of our legacy term contracts. We charge prevailing market prices per hour for work performed in the spot market. We may also charge fees for setup and mobilization of equipment depending on the job, additional equipment used on the job, if any, and other miscellaneous consumables. Generally, these fees and other charges vary depending on the equipment and personnel required for the job and market conditions in the region in which the services are performed. We also source chemicals and proppants that are consumed during the fracturing process. We charge our customers a fee for materials consumed in the process and a handling fee for any chemicals and proppants supplied by the customer. Materials charges reflect the cost of the materials plus a markup and are based on the actual quantity of materials used in the fracturing process.

Coiled Tubing and Other Well Stimulation Services. Our coiled tubing business currently consists of 27 coiled tubing units. During 2013, we deployed six new extended-reach larger-diameter coiled tubing units in response to an industry trend towards such higher-specification equipment, and we also modified certain of our existing coiled tubing equipment to meet customer demand. Demand for these units remained strong across our operating areas, and accordingly, in December 2013, we purchased three additional high-capacity coiled tubing units and ancillary equipment. Two of these units were placed into service in mid-February, and we expect to deploy the other unit during the first quarter of 2014. Our 2013 investments in this business were in line with the continued broadening of our customer base and geographic footprint, and we intend to continue investing in the growth of this business.

Our coiled tubing operations contributed $140.4 million, or 13.1%, to our consolidated revenue, and we completed 4,035 coiled tubing jobs during the year ended December 31, 2013, compared to $140.2 million of revenue and 3,719 coiled tubing jobs for the previous year. Utilization in our coiled tubing services improved for the year ended December 31, 2013 compared to the prior year, in large part due to the successful deployment of our new and modified extended-reach larger-diameter coiled tubing units as well as our expanded geographic presence into the Northeast. However, revenue per job decreased primarily due to a more competitive pricing environment in our primary operating areas.

Our coiled tubing services are generally provided in the spot market at prevailing prices per hour, although we do have one contract in place with a major operator for dedicated coiled tubing and associated services. We may also charge fees for setup and mobilization of equipment depending on the job. The setup charges and hourly rates are determined by a competitive bid process and vary with the type of service to be performed, the equipment and personnel required for the job and market conditions in the region in which the service is performed. We also charge customers for the materials, such as stimulation fluids, nitrogen and coiled tubing materials that we use in each job. Materials charges reflect the cost of the materials plus a markup and are based on the actual quantity of materials used for the project.

Our other well stimulation services primarily include nitrogen, pressure pumping and thru-tubing services. Additionally, with the development of our specialty chemicals business and our strategic

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acquisitions during 2013, we now provide specialty chemicals for completion and production services, as well as downhole tools and related directional drilling technology and data control systems. After an evaluation of these businesses, it was determined that each is appropriately accounted for in our Stimulation and Well Intervention Services segment.

Our other well stimulation services contributed $16.7 million of revenue or 1.6% to our consolidated revenue for the year ended December 31, 2013, up from $15.2 million during the year ended December 31, 2012, the substantial majority of which was generated by our nitrogen, pressure pumping and thru-tubing services.

Wireline Services Segment

Our Wireline Services segment provides cased-hole wireline and other complementary services, including logging, perforating, pipe recovery, pressure testing and pumpdown services, which are critical throughout a well’s lifecycle. Our Wireline Services segment currently consists of 69 wireline units and 33 pumpdown units, as well as pressure control and other ancillary equipment. During 2013, we deployed six new wireline units and fourteen pumpdown units. We currently intend to deploy an additional two new wireline units and four new pumpdown units during the first quarter of 2014.

Our Wireline Services segment contributed $278.8 million, or 26.0%, to our consolidated revenue during the year ended December 31, 2013, compared to $130.1 million from the date of acquisition through December 31, 2012. We have rapidly grown this business since acquiring it in June 2012, and we intend to continue to adding capacity as we increase our market share through the expansion of our customer base and geographic reach.

Services provided by this segment are generally provided at prevailing rates in the spot market on a job-by-job basis. The rates are determined by a competitive bid process and vary with the type of service to be performed, the equipment and personnel required for the job and market conditions in the region in which the service is performed.

Equipment Manufacturing Segment

Our Equipment Manufacturing segment constructs oilfield equipment, including hydraulic fracturing pumps, coiled tubing units and pressure pumping units, for third-party customers in the energy services industry, as well as for our Stimulation and Well Intervention Services and Wireline Services segments. This segment also provides equipment repair and refurbishment services and oilfield parts and supplies to the energy services industry, and to our Stimulation and Well Intervention Services and Wireline Services segments.

Our Equipment Manufacturing segment contributed $8.1 million, or 0.8%, of our consolidated revenue during the year ended December 31, 2013, compared to $41.1 million the previous year. This business continues to be negatively impacted by the prevailing equipment overcapacity in the domestic onshore completion industry and we do not expect third-party sales to significantly improve over the near term. During 2013, we took advantage of the slowdown to enhance and add efficiencies in the manufacturing throughput process, which we believe will enable us to achieve greater profitability and cash flow savings once the market begins to improve. Additionally, our manufacturing business continues to provide us with cash flow savings from equipment manufacturing and refurbishment capabilities, and supports active management of parts and supplies purchasing.

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

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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.

Our business depends on the capital spending programs of our customers. Revenue from our Stimulation and Well Intervention Services and Wireline Services segments are generated by providing services to oil and natural gas exploration and production companies throughout the United States. Demand for our services is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the United States, which in turn is affected by current and expected levels of oil and natural gas prices. The level of exploration, development and production activities by these customers also impacts demand for our Equipment Manufacturing segment’s services and products. Companies in the energy services industry have historically tended to delay capital equipment projects, including maintenance and upgrades, during industry downturns like the current one, which has been characterized by excess equipment capacity across the U.S. hydraulic fracturing market.

The oil and gas industry has traditionally been volatile, is highly sensitive to a combination of long-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 and workover budget, as well as domestic and international economic conditions, political instability in oil producing countries and merger, acquisition and divestiture activity among exploration and production companies. The volatility of the oil and gas industry, and the consequent impact on exploration and production activity, has adversely impacted, and could continue to adversely impact, the level of drilling and workover activity by our customers. This volatility affects the demand for our services and our ability to negotiate pricing at levels generating desirable margins, especially in our hydraulic fracturing business.

Natural gas prices declined in 2009 and remained depressed through 2013, 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 much of the current horizontal drilling and completion related activity is concentrated in oily- and liquids-rich formations. Commodity prices will likely continue to hamper drilling activities in natural gas shale plays over the near term. The excess completion capacity into the oily- and liquids-rich regions and weakness in the price of natural gas has led to increased competition among energy service companies in the oily regions and negatively affected the spot market pricing for our services.

Although, we do not expect the current environment to significantly improve without an increase in rig count, we are confident in our ability to successfully compete in and manage through the challenges. Entering the fourth quarter of 2013 we saw an increase in activity across our core service lines. However, during December, we experienced a pause in activity by our customers as a result of the holidays, as well as some disruption in our services due to 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. Given current activity levels, and based on the progress we made growing our business and expanding our customer base and geographic reach during 2013, we believe we will be able to improve overall utilization across our operations over the course of 2014. In spite of the recent increase in demand, pricing has remained flat and, given the continued level of competition in the market, we do not expect it to increase over the near term.

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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. With the majority of our hydraulic fracturing equipment now working in the spot market, the highly competitive operating and pricing environments for our services will have a significant impact on our level of profitability.

The markets in which we operate are highly competitive and the U.S. pressure pumping market experienced sustained pressures through 2013. Our results for the year ended December 31, 2013 compared to the year ended December 31, 2012 were negatively impacted by increased spot market exposure in our hydraulic fracturing operations, which resulted in lower utilization and pricing for our services. Our results of operations for the year ended December 31, 2012 compared to the year ended December 31, 2011 were significantly impacted by the dramatic growth of our asset base during that time.

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 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		738,947			686,811			52,136
Selling, general and administrative expenses		136,910			94,556			42,354
Research and development		5,020			—			5,020
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	)
Provision for income taxes		41,313			95,079			(53,766	)
Net income	$	66,405		$	182,350		$	(115,945	)

Revenue

Revenue decreased $41.2 million, or 4%, 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.

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Direct Costs

Direct costs increased $52.1 million, or 7.6%, to $738.9 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 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; 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 & 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 Research & Technology capabilities. In order to more effectively communicate our commitment to technological advancement, we elected to include a new line item 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

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.

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Income Taxes

We recorded a tax provision of $41.3 million for the year ended December 31, 2013, at an effective rate of 38.4%, compared to a tax provision of $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.

Results for the Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

The following table summarizes the change in our results of operations for the year ended December 31, 2012 when compared to the year ended December 31, 2011 (in thousands):

	Years Ended December 31,
	2012			2011			$ Change
Revenue	$	1,111,501		$	758,454		$	353,047
Costs and expenses:
Direct costs		686,811			432,298			254,513
Selling, general and administrative expenses		94,556			41,076			53,480
Depreciation and amortization		46,912			22,919			23,993
(Gain)/Loss on disposal of assets		692			(25	)		717
Operating income		282,530			262,186			20,344
Other expense:
Interest expense, net		(4,996	)		(4,221	)		(775	)
Loss on early extinguishment of debt		—			(7,605	)		7,605
Other expense, net		(105	)		(40	)		(65	)
Total other expenses, net		(5,101	)		(11,866	)		6,765
Income before income taxes		277,429			250,320			27,109
Provision for income taxes		95,079			88,341			6,738
Net income	$	182,350		$	161,979		$	20,371

Revenue

Revenue increased $353.0 million, or 47%, to $1.1 billion for the year ended December 31, 2012, as compared to $758.5 million for the year ended December 31, 2011. This increase was primarily due to the addition of hydraulic fracturing equipment and coiled tubing units, resulting in an additional $203.9 million in Stimulation and Well Intervention Services revenue, the acquisition of our wireline business in June 2012 resulting in an additional $130.1 million in Wireline Services revenue and the acquisition of our equipment manufacturing business in April 2011 resulting in $19.1 million in incremental Equipment Manufacturing revenue.

Direct Costs

Direct costs increased $254.5 million, or 59%, to $686.8 million for the year ended December 31, 2012, as compared to $432.3 million for the year ended December 31, 2011 due to $164.4 million in the Stimulation and Well Intervention Services segment primarily due to the significant increase in revenue. To a lesser extent, direct costs increased by $73.1 million for Wireline Services due to the acquisition of our wireline business in June 2012 and $17.0 million in Equipment Manufacturing due to higher demand. As a percentage of revenue, direct costs increased to 62% for the year ended December 31, 2012 from 57% for the year ended December 31, 2011. Direct costs as a percentage of revenue increased due to a decline in utilization and pricing in our hydraulic fracturing service line as a result of excess equipment capacity in the U.S. pressure pumping market.

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Selling, General and Administrative Expenses (“SG&A”)

SG&A increased $53.5 million, or 130%, to $94.6 million for the year ended December 31, 2012, as compared to $41.1 million for the year ended December 31, 2011. The increase was primarily due to $19.9 million in SG&A costs related to the acquisition of our wireline business in June 2012, $8.4 million in higher payroll and personnel costs associated with the continued hiring of personnel to support our growth, $7.5 million in higher long-term and short-term incentive costs, $5.9 million in legal settlements, $3.4 million in professional fees and $2.8 million in incremental SG&A costs related to the acquisition of our equipment manufacturing business in April 2011.

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 and December 31, 2011 to conform to our year ended December 31, 2013 presentation. The amount of the reclassification for the year ended December 31, 2012 and December 31, 2011 was $13.8 million and $7.3 million, respectively.

Depreciation and Amortization

Depreciation and amortization expenses increased $24.0 million, or 105%, to $46.9 million for the year ended December 31, 2012, as compared to $22.9 million for the year ended December 31, 2011. The increase was primarily related to $12.2 million from the Stimulation and Well Intervention Services segment due to the addition and deployment of new equipment and $11.8 million from the Wireline Services segment due to the acquisition of our wireline business in June 2012.

Interest Expense

Interest expense increased by $0.8 million, or 18%, to $5.0 million for the year ended December 31, 2012, as compared to $4.2 million for the year ended December 31, 2011. The increase was primarily attributable to higher average debt balances for 2012.

Loss on Early Extinguishment of Debt

We incurred $7.6 million in costs associated with the early extinguishment of our previous credit facility and subordinated term loan during the year ended December 31, 2011. These costs consisted of $4.7 million in early termination penalties on the subordinated term loan and $2.9 million related to accelerated recognition of deferred financing costs on the previous credit facility and subordinated term loan. Immediately following these extinguishments, we entered into our Credit Facility, which is further discussed in “Description of Our Indebtedness”. We did not incur any costs associated with early extinguishment of debt during the year ended December 31, 2012.

Income Taxes

We recorded a tax provision of $95.1 million for the year ended December 31, 2012, at an effective rate of 34.3%, compared to a tax provision of $88.3 million for the year ended December 31, 2011, at an effective rate of 35.3%. The 1.0% decrease in our effective rate year over year is primarily attributable to an increase in tax deductions that are not recognized for book purposes.

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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 technological advancement. Our capital expenditures, maintenance costs and other expenses have increased substantially over the last few years to support our growth. As we execute our long term growth strategy and advance on our strategic initiatives, we anticipate that these costs will continue to increase over 2014 and beyond.

We are actively exploring opportunities to 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. In spite of challenging market conditions, we have continued to generate solid cash flows that have allowed us to repay a large portion of the debt we incurred for the June 2012 acquisition of our wireline business, while continuing to fund capital expenditures. Our free cash flow and strong balance sheet allows 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 hydraulic fracturing services could cause us to reduce our capital expenditures.

Our 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 $400.0 million of revolving credit. As of December 31, 2013, we had $150.0 million outstanding under the Credit Facility and $0.7 million in letters of credit, and as of February 21, 2014, we had $175.0 million outstanding and $2.0 million in letters of credit, leaving $223.0 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, 2013, and through the date of this report, we are in compliance with these covenants.

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

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

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Capital expenditures totaled $158.0 million in the year ended December 31, 2013, including investments in new equipment and service lines and maintenance capital for our existing service lines. Our 2014 planned capital expenditures are expected to range from $200.0 million to $220.0 million based on current equipment orders and growth estimates, excluding any acquisitions. Currently, our capital expenditures are weighted toward the first nine months of 2014, with the majority intended to be utilized on new hydraulic fracturing equipment, as well as new coiled tubing and wireline equipment. However, if we see any indication of a pullback in customer demand we have the flexibility to immediately cease manufacturing and use the components with our existing equipment. Our other planned capital expenditures include maintenance capital for our core service lines, as well as approximately $25.0 million to $35.0 million allocated to the growth of our other businesses and advancement on our strategic initiatives.

We believe we are well-positioned to finance our future growth. Despite the highly competitive environment, which impacted our 2013 financial results, we have continued to generate strong cash flows. On June 5, 2012, we increased the borrowing base under our Credit Facility to $400.0 million from $200.0 million and as of February 21, 2014, $223.0 million was available for borrowing. We believe our cash flows from operations and existing capital, coupled with borrowings under our Credit Facility, will be sufficient to fund our 2014 capital expenditures and sustain our spending levels over the next 12 months. We plan to continue to monitor the economic environment and demand for our services and adjust our business strategy as necessary.

We continually monitor new advances in equipment and down-hole technology, as well as new 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 development capabilities through the establishment of a new research and technology division. We have assembled a team of technology-focused engineers and recently completed construction of a new research and technology facility. We will continue to invest in our research and technology capabilities as a key element of our growth strategy. We believe that these efforts will enable us to more effectively compete against larger integrated energy services companies, both domestically and internationally.

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 recently opened an office in Dubai where we are assembling a team of sales, operational and administrative personnel. During 2014, 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.

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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,
	2013			2012			2011
Cash flow provided by (used in):
Operating activities	$	187,278		$	254,683		$	171,702
Investing activities		(171,472	)		(458,146	)		(165,545	)
Financing activities		(15,834	)		171,125			37,806
Net change in cash and cash equivalents	$	(28	)	$	(32,338	)	$	43,963

Cash Provided by Operating Activities

Net cash provided by operating activities was $67.4 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.

Net cash provided by operating activities was $83.0 million higher for the year ended December 31, 2012 as compared to the same period in 2011. The most significant components resulting in the increase in cash provided by operating activities were a decrease in the year over year growth of accounts receivable, higher net income and higher depreciation and amortization costs, partially offset by an increase in current tax expense. The decrease in the growth of our accounts receivable balance is primarily attributable to a reduction in the growth rate of our service lines near the end of 2012 compared to the end of 2011. The increase in net income was attributable to the increase in our revenue year over year in connection with the deployment of additional hydraulic fracturing fleets and coiled tubing units, as well as the acquisition of our wireline business. Likewise, the increase in our depreciation and amortization costs was attributable to the growth of our fleet of hydraulic fracturing and coiled tubing assets as well as the incremental depreciation and amortization costs incurred in connection with the acquisition of our wireline business. Current tax expense is higher year over year primarily as a result of the decrease in depreciation on our fixed assets for income tax purposes due to bonus depreciation deductions taken in prior years and the decrease in the rate of bonus depreciation to 50% for 2012 qualifying assets.

Cash Flows Used in Investing Activities

Net cash used in investing activities decreased $286.7 million for the year ended December 31, 2013 as compared to the same period in 2012. This decrease 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.

Net cash used in investing activities increased $292.6 million for the year ended December 31, 2012 as compared to the same period in 2011. This increase was due primarily to the cash paid to acquire our wireline business as compared to the cash paid to acquire our equipment manufacturing business, along with increased capital expenditures. For the year ended December 31, 2012, we paid total cash consideration of $273.4 million, net of cash acquired, in connection with the acquisition of our wireline business. For the year ended December 31, 2011, we spent $27.2 million to acquire our equipment manufacturing business.

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Cash Flows Provided by Financing Activities

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.

Net cash provided by financing activities increased $133.3 million for the year ended December 31, 2012 as compared to the same period in 2011. As mentioned above, 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, 2013 (in thousands):

Contractual Obligation	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Credit Facility(1)	$	161,166	$	4,884	$	156,282	$	—	$	—
Capital leases(2)		49,394		4,766		8,305		7,216		29,107
Operating leases		29,405		9,130		9,056		4,397		6,822
Service Equipment and other capital expenditures		12,209		12,209		—		—		—
Total	$	252,174	$	30,989	$	173,643	$	11,613	$	35,929

(1) Includes estimated interest costs at an interest rate of 2.4% along with related charges.

(2) Capital lease amounts include $7.0 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, 2013.

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.

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The Amendment increased our borrowing capacity under the Credit Facility to $400.0 million. To effectuate this increase, new financial institutions were added to the Credit Facility as lenders and certain existing lenders severally agreed to increase their respective commitments. Pursuant to the Amendment, the aggregate amount by which we may periodically increase commitments through incremental facilities was increased from $75.0 million to $100.0 million, the sublimit for letters of credit was left unchanged at $200.0 million and the sublimit for swing line loans was increased from $15.0 million to $25.0 million. On June 7, 2012, we drew $220.0 million from the Credit Facility to fund a portion of the purchase price of the acquisition of our wireline business. As of December 31, 2013, we had $150.0 million outstanding under the Credit Facility and $0.7 million in letters of credit, and as of February 21, 2014, we had $175.0 million outstanding and $2.0 million in letters of credit, leaving $223.0 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, 2013 was 2.4%.

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 maintenance capital expenditures.

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, 2013, 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 and renewals 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.

Goodwill, Intangible Assets and Amortization. The carrying amount of goodwill is tested annually for impairment in the fourth quarter and whenever events or circumstances indicate their carrying value may not be recoverable. Impairment testing is conducted at the reporting unit level of our businesses, consistent with the presentation of our operating segments.

Before employing detailed impairment testing methodologies, we may first evaluate the likelihood of impairment by considering qualitative factors relevant to each reporting unit, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. If we first utilize a qualitative approach and determine that it is more likely than not that goodwill is impaired, we then apply detailed testing methodologies. Otherwise, we conclude that no impairment has occurred. We 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. Our 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, we recognize an impairment loss in an amount equal to the excess, not to exceed the carrying value.

Our detailed impairment analysis involves the use of discounted cash flow models. 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, gross profit rates, SG&A rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. We determine discount rates separately for each reporting unit using the capital asset pricing model. We also use comparable market earnings multiple data and our Company’s market capitalization to corroborate our reporting unit valuations.

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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. The annual goodwill impairment testing has been completed for each of our reporting units during the fourth quarter, and as the fair value of each reporting unit was in excess of the respective reporting unit’s carrying value, it has been determined that our $205.8 million of goodwill is not impaired.

We have 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, we may first evaluate the likelihood of impairment by considering qualitative factors. Our detailed impairment test for indefinite lived intangible assets encompasses calculating a fair value of an indefinite lived intangible asset and comparing the fair value to its carrying value. No impairment with respect to indefinite lived intangible assets was recorded during 2013.

We have not identified any impairment in goodwill or other indefinite lived intangible assets during the past three years. The effect of a 2% increase or decrease in the discount rate used to determine the fair value of the reporting unit or the indefinite lived intangible asset does not change our conclusion regarding the identification of any impairment in goodwill or other indefinite lived intangible assets.

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.

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 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.

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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.

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. 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 chemicals and proppants consumed during the course of the service. The field ticket may also include charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables.

Historically, most of our hydraulic fracturing services were performed under six legacy term contracts, which had minimum utilization requirements and favorable pricing terms relative to the spot market pricing experienced during 2013. Over the course of 2013, all but one of our legacy term contracts expired, however, we were able to transition two of them into short-term pricing agreements. We also reduced the pricing terms of our remaining term contract to reflect rates more consistent with spot market pricing. 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. Under pricing agreements, our customers typically commit to targeted utilization levels 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 to then-current market rates upon the agreement of both parties.

Our exposure to the spot market increased significantly over the course of 2013 with the expiration of all but one of our legacy term contracts. Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate. We may also charge fees for setup and mobilization of equipment depending on the job, additional equipment used on the job, if any, and materials that are consumed during the fracturing process. Generally, these fees and other charges vary depending on the equipment and personnel required for the job and market conditions in the region in which the services are performed.

Coiled Tubing and Other Well Stimulation Revenue. We enter into arrangements to provide coiled tubing and other well stimulation services, primarily including nitrogen, pressure pumping and thru-tubing services. Jobs for these services are typically short-term in nature and each job can last 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 mobilization of the equipment to the location, the service performed, the personnel on the job, additional equipment used on the job, if any, and miscellaneous consumables used throughout the course of the service. We typically charge the customer on an hourly basis for these services at agreed-upon spot market rates.

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Revenue from Materials Consumed While Performing Services. We generate revenue from chemicals and proppants that are consumed while performing hydraulic fracturing services. For services performed on a spot market basis, we typically provide the necessary chemicals and proppants, and the customer is billed for those materials at cost plus an agreed-upon markup. For services performed on a contractual basis, when the chemicals and proppants are provided by us, the customer is billed for those materials at a negotiated contractual rate. When chemicals and proppants are supplied by the customer, we typically charge handling fees based on the amount of chemicals and proppants used.

In addition, ancillary to coiled tubing and related well intervention service revenue, we generate revenue from various fluids and supplies that are necessarily consumed during those processes.

Wireline Revenue. Wireline revenue is generated from the performance of cased-hole wireline and other complementary services, including logging, perforating, pipe recovery, pressure testing and pumpdown services. These jobs 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. We typically charge 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 equipment, conduct equipment repair services 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 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 $1.7 million at December 31, 2013 and $1.1 million at December 31, 2012. Bad debt expense was $0.7 million, $0.6 million $0.4 million for the years ended December 31, 2013, 2012 and 2011, 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

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generally filed months after the close of our annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when we recognize income tax expenses and benefits.

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

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. In assessing the likelihood and extent that deferred tax assets will be realized, consideration is given to projected future taxable income and tax planning strategies. A valuation allowance is recorded when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. We will record income tax related interest and penalties, if applicable, as a component of the provision for income tax expense.

Recent Accounting Pronouncements

None.

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, 2013, 2012 and 2011. 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 (sand), chemicals, guar, coiled tubing and fluid supplies. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials (particularly guar and sand) 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.

-53-

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, 2013 and 2012 would have resulted in an increase in interest expense and a corresponding decrease in net income of approximately $1.5 million and $1.7 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	56
Reports of Independent Registered Public Accounting Firm	57
Consolidated Balance Sheets as of December 31, 2013 and 2012	59
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	60
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December  31, 2013, 2012 and 2011	61
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	62
Notes to Consolidated Financial Statements	63

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MANAGEMENT’S REPORTON 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, 2013 using the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal 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, 2013.

The Company’s internal control over financial reporting as of December 31, 2013 has been audited by UHY 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	Randall C. McMullen, Jr.	Mark C. Cashiola
Chairman and Chief Executive Officer (Principal Executive Officer)	President, Chief Financial Officer and Treasurer (Principal Financial Officer)	Vice President and Controller (Principal Accounting Officer)

February 26, 2014

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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 sheets of C&J Energy Services, Inc. (a Delaware corporation) and subsidiaries (collectively, the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three 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 consolidated financial position of C&J Energy Services, Inc. and subsidiaries as of December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of C&J Energy Services, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established inInternal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 26, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ UHY LLP

Houston, Texas

February 26, 2014

-57-

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

C&J Energy Services, Inc.

We have audited C&J Energy Services, Inc. (a Delaware corporation) and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included herein. 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, testing and evaluating the design and operating effectiveness of internal control and 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 condition, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, C&J Energy Services, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of C&J Energy Services, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013, and our report dated February 26, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ UHY LLP

Houston, Texas

February 26, 2014

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share data)

	As of December 31,
	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	14,414	$	14,442
Accounts receivable, net		152,696		166,517
Inventories, net		70,946		60,659
Prepaid and other current assets		17,066		4,948
Deferred tax assets		1,722		3,613
Total current assets		256,844		250,179
Property, plant and equipment, net		535,574		433,727
Other assets:
Goodwill		205,798		196,512
Intangible assets, net		123,038		123,487
Deposits on equipment under construction		4,331		1,033
Deferred financing costs, net		2,688		3,848
Other noncurrent assets		4,027		3,971
Total assets	$	1,132,300	$	1,012,757
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	88,576	$	69,617
Payroll and related costs		13,711		10,896
Accrued expenses		18,619		17,286
Income taxes payable		266		4,029
Customer advances and deposits		1,035		1,092
Other current liabilities		2,926		2,122
Total current liabilities		125,133		105,042
Deferred tax liabilities		145,215		132,551
Long-term debt and capital lease obligations		164,205		173,705
Other long-term liabilities		1,596		1,568
Total liabilities		436,149		412,866
Commitments and contingencies
Stockholders’ equity
Common stock, par value of $0.01, 100,000,000 shares authorized, 54,604,124 issued and outstanding at December 31, 2013 and 53,131,823 issued and outstanding at December 31, 2012		546		531
Additional paid-in capital		254,188		224,348
Retained earnings		441,417		375,012
Total stockholders’ equity		696,151		599,891
Total liabilities and stockholders’ equity	$	1,132,300	$	1,012,757

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF OPERATIONS

(Amounts in thousands, except per share data)

	Years Ended December 31,
	2013			2012			2011
Revenue	$	1,070,322		$	1,111,501		$	758,454
Costs and expenses:
Direct costs		738,947			686,811			432,298
Selling, general and administrative expenses		136,910			94,556			41,076
Research and development		5,020			—			—
Depreciation and amortization		74,703			46,912			22,919
(Gain) loss on disposal of assets		527			692			(25	)
Operating income		114,215			282,530			262,186
Other income (expense):
Interest expense, net		(6,550	)		(4,996	)		(4,221	)
Loss on early extinguishment of debt		—			—			(7,605	)
Other expense, net		53			(105	)		(40	)
Total other income (expense)		(6,497	)		(5,101	)		(11,866	)
Income before income taxes		107,718			277,429			250,320
Income tax expense		41,313			95,079			88,341
Net income	$	66,405		$	182,350		$	161,979
Net income per common share:
Basic	$	1.25		$	3.51		$	3.28
Diluted	$	1.20		$	3.37		$	3.19
Weighted average common shares outstanding:
Basic		53,038			52,008			49,315
Diluted		55,367			54,039			50,780

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF CHANGESIN STOCKHOLDERS’ EQUITY

(Amounts in thousands)

										Retained
	Common Stock						Additional			Earnings
	Number of Shares			Amount, at $0.01 par value			Paid-in Capital			(Accumulated Deficit)		Total
Balance, December 31, 2010		47,499		$	475		$	78,288		$	30,683	$	109,446
Issuance of common stock		4,300			43			112,104			—		112,147
Exercise of stock options		88			1			124			—		125
Tax effect of stock-based compensation		—			—			512			—		512
Stock-based compensation		—			—			10,846			—		10,846
Net income		—			—			—			161,979		161,979
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

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF CASH FLOWS

(Amounts in thousands)

	Years Ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Net income	$	66,405		$	182,350		$	161,979
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		74,703			46,912			22,919
Deferred income taxes		16,513			15,926			45,903
Provision for doubtful accounts, net of write-offs		689			600			415
Equity in loss of unconsolidated affiliate		160			—			—
(Gain) Loss on disposal of assets		527			692			(25	)
Stock-based compensation expense		22,581			18,012			10,846
Excess tax benefit from stock-based award activity		(3,450	)		(1,916	)		(512	)
Amortization of deferred financing costs		1,160			923			703
Inventory write-down		870			—			—
Write-off of deferred financing costs related to early extinguishment of debt		—			—			2,899
Changes in operating assets and liabilities:
Accounts receivable		14,704			(10,621	)		(72,323	)
Inventories		(10,495	)		(11,263	)		(29,201	)
Prepaid expenses and other current assets		(12,405	)		7,107			(5,416	)
Accounts payable		18,168			(442	)		41,426
Accrued liabilities		2,710			5,373			5,366
Accrued taxes		(438	)		3,681			(5,607	)
Deferred income		200			600			(4,000	)
Other		(5,324	)		(3,251	)		(3,670	)
Net cash provided by operating activities		187,278			254,683			171,702
Cash flows from investing activities:
Purchases of and deposits on property, plant and equipment		(157,987	)		(182,179	)		(140,723	)
Proceeds from disposal of property, plant and equipment		1,151			434			2,400
Payments made for business acquisitions, net of cash acquired		(14,636	)		(273,401	)		(27,222	)
Investment in unconsolidated subsidiary		—			(3,000	)		—
Net cash used in investing activities		(171,472	)		(458,146	)		(165,545	)
Cash flows from financing activities:
(Payments) proceeds on revolving debt, net		(20,306	)		170,000			(3,000	)
Proceeds from long-term debt		—			—			12,750
Repayments of long-term debt		(638	)		—			(81,789	)
Repayments of capital lease obligations		(2,184	)		(1,121	)		—
Financing costs		—			(2,243	)		(2,939	)
Proceeds from initial public offering, net of transaction fees		—			—			112,147
Proceeds from stock options exercised		5,219			2,573			125
Employee tax withholding on restricted stock vesting		(1,375	)		—			—
Excess tax benefit from stock-based award activity		3,450			1,916			512
Net cash provided by (used in) financing activities		(15,834	)		171,125			37,806
Net (decrease) increase in cash and cash equivalents		(28	)		(32,338	)		43,963
Cash and cash equivalents, beginning of year		14,442			46,780			2,817
Cash and cash equivalents, end of year	$	14,414		$	14,442		$	46,780
Supplemental cash flow disclosures:
Cash paid for interest	$	5,473		$	3,975		$	8,417
Cash paid for income taxes	$	38,819		$	75,619		$	46,692
Non-cash consideration for business acquisition	$	2,556		$	—		$	—

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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

C&J Energy Services, Inc., a Delaware corporation, was founded in Texas in 1997. 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 through its Stimulation and Well Intervention Services segment and cased-hole wireline and other complementary services through its Wireline Services segment to oil and natural gas exploration and production companies throughout the United States. In addition, the Company manufactures, refurbishes and repairs equipment and provides oilfield parts and supplies for third-party customers in the energy services industry through its Equipment Manufacturing segment, and also fulfills the Company’s internal equipment demands through this segment. See “Note 11 – Segment Information” for further discussion regarding the Company’s reportable segments. With the exception of C&J International B.V. and C&J International Middle East FZCO, all of the Company’s consolidated subsidiaries are currently located and operated within North America. As used herein, references to the “Company” or “C&J” are to C&J Energy Services, Inc. together with its consolidated subsidiaries.

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 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, useful lives used in depreciation and amortization, 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 and balances in operating bank accounts, amounts due from depository institutions, interest-bearing and deposits in other banks, and money market accounts. The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at the amount billed to customers and are ordinarily due upon receipt. 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, 2013 and 2012, the allowance for doubtful accounts totaled $1.7 million and $1.1 million, respectively. Bad debt expense of $0.7 million, $0.6 million and $0.4 million was included in selling, general, and administrative expenses on the consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011, respectively.

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, and supplies and materials for the segments’ operations. Inventories for the Equipment Manufacturing segment consist of raw materials and work-in-process, including equipment components and supplies and materials. See “Note 11 – Segment Information” for further discussion regarding the Company’s reportable segments.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2013			2012
Raw materials	$	31,445		$	21,551
Work-in-process		3,652			1,523
Finished goods		36,690			38,164
Total inventory		71,787			61,238
Inventory reserve		(841	)		(579	)
Inventory, net of reserve	$	70,946		$	60,659

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 and renewals 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 $64.6 million, $39.4 million and $19.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. Major classifications of property, plant and equipment and their respective useful lives are as follows (in thousands):

	Estimated	As of December 31,
	Useful Lives	2013			2012
Land	Indefinite	$	2,225		$	1,454
Building and leasehold improvements	5-25 years		50,163			26,856
Office furniture, fixtures and equipment	3-5 years		10,878			6,639
Machinery and equipment	3-10 years		529,854			397,747
Transportation equipment	5 years		46,425			26,048
			639,545			458,744
Less: accumulated depreciation			(148,954	)		(84,848	)
			490,591			373,896
Assets not yet placed in service			44,983			59,831
Property, plant and equipment, net		$	535,574		$	433,727

-64-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Goodwill, Intangible Assets and Amortization. The carrying amount of goodwill is tested at least annually for impairment and more frequently if events or circumstances indicate their carrying value may not be recoverable. Impairment testing is conducted at the reporting unit level, consistent with the presentation of the Company’s operating segments.

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 discounted cash flow models. 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, gross profit rates, SG&A rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. Discount rates are determined separately for each reporting unit using the capital asset pricing model. Comparable market earnings multiple data is also used as well as the Company’s market capitalization 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. The annual goodwill impairment testing has been completed for each of the Company’s reporting units during the fourth quarter, and as the fair value of each reporting unit was in excess of the respective reporting unit’s carrying value, it has been determined that the $205.8 million of goodwill is not impaired.

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 a fair value of an indefinite lived intangible asset and comparing the fair value to its carrying value. No impairment with respect to indefinite lived intangible assets was recorded during 2013.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Intangible assets consist of the following (in thousands):

	Amortization	As of December 31,
	Period	2013			2012
Trade name	10-15 years	$	27,665		$	27,275
Customer relationships	8-15 years		100,593			100,193
Non-compete, backlog and patent	11 - 48 months		4,601			4,601
Developed technology	10 years		2,110			—
IPR&D	Indefinite		7,598			854
Trade name - Total Equipment	Indefinite		6,247			6,247
			148,814			139,170
Less: accumulated amortization			(25,776	)		(15,683	)
Intangible assets, net		$	123,038		$	123,487

Amortization expense for the years ended December 31, 2013, 2012 and 2011 totaled $10.1 million, $7.5 million and $3.7 million, respectively.

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

Years Ending December 31,
2014		10,187
2015		9,535
2016		9,269
2017		9,135
2018		9,135
Thereafter		61,932
	$	109,193

Impairment of Long-Lived Assets. Long-lived assets, which include property, plant and equipment, and intangible assets with finite lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows, excluding interest expense. The impairment loss is determined by comparing the fair value with the carrying value of the related assets. For the years ended December 31, 2013, 2012 and 2011, no indicators of impairment were present.

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NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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, $0.9 million and $0.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Accumulated amortization of deferred financing costs was $2.5 million and $1.3 million at December 31, 2013 and 2012, respectively. Estimated future amortization expense relating to deferred financing costs is as follows (in thousands):

Years Ending December 31,
2014		1,160
2015		1,160
2016		368
	$	2,688

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. 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 chemicals and proppants consumed during the course of the service. The field ticket may also include charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables.

Historically, most of the Company’s hydraulic fracturing services were performed under six legacy term contracts. Over the course of 2013, all but one of these term contracts expired, with two transitioning into short-term pricing agreements. Under the Company’s 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.

Pursuant to pricing agreements, customers typically commit to targeted utilization levels 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 to then-current market rates upon the agreement of both parties.

Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate. The Company may also charge fees for setup and mobilization of equipment depending on the job, additional equipment used on the job, if any, and materials that are consumed during the fracturing process. Generally, these fees and other charges vary depending on the equipment and personnel required for the job and market conditions in the region in which the services are performed.

Coiled Tubing and Other Well Stimulation Revenue. The Company enters into arrangements to provide coiled tubing and other well stimulation services, primarily including nitrogen, pressure pumping and thru-tubing services. 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 mobilization of the equipment to the location, the service performed, the personnel on the job, additional equipment used on the job, if any, and miscellaneous consumables used throughout the course of the service. The Company typically charges the customer for these services on an hourly basis at agreed-upon spot market rates.

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NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Wireline Revenue. Wireline revenue is generated from the performance of cased-hole wireline and other complementary services, including logging, perforating, pipe recovery, pressure testing and pumpdown services. These jobs 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 officers, employees, consultants and non-employee directors. As of December 31, 2013, 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 date of grant. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period. 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. During 2013, the Company made 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.

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NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

The carrying value of this equity method investment at December 31, 2013 was $2.8 million and is included in other noncurrent assets on the consolidated balance sheets. The Company’s share of the net loss from the unconsolidated affiliate was approximately $160,000 for the year ended December 31, 2013 and is included in other expense, net, on the consolidated statements of operations.

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

The 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 amounts recognized relating to interest and penalties in the consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011, respectively. The Company had no uncertain tax positions as of December 31, 2013.

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.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2013		2012		2011
	(In thousands, except per share amounts)
Numerator:
Net income attributed to common shareholders	$	66,405	$	182,350	$	161,979
Denominator:
Weighted average common shares outstanding - basic		53,038		52,008		49,315
Effect of potentially dilutive securities:
Stock options		2,096		1,979		1,465
Restricted stock		233		52		—
Weighted average common shares outstanding - diluted		55,367		54,039		50,780
Earnings per common share:
Basic	$	1.25	$	3.51	$	3.28
Diluted	$	1.20	$	3.37	$	3.19

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,
	2013		2012		2011
	(In thousands)
Basic earnings per share:
Unvested restricted stock		1,194		748		—
Diluted earnings per share:
Anti-dilutive stock options		1,054		1,193		2,344
Anti-dilutive restricted stock		164		30		—
Potentially dilutive securities excluded as anti-dilutive		1,218		1,223		2,344

Recent Accounting Pronouncements. None.

Reclassifications. Certain reclassifications have been made to prior period consolidated financial statements to conform to current period presentations. These reclassifications had no effect on the consolidated financial position, results of operations or cash flows of the Company.

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NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 - Long-Term Debt and Capital Lease Obligations

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

	As of December 31,
	2013			2012
Senior secured revolving credit facility maturing on April 19, 2016	$	150,000		$	170,000
Capital leases		17,065			5,763
Total debt and capital lease obligations		167,065			175,763
Less: amount maturing within one year		(2,860	)		(2,058	)
Long-term debt and capital lease obligations	$	164,205		$	173,705

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, has a borrowing base of $400.0 million (the “Credit Facility”). The amendment increased, among other things, the Company’s borrowing capacity under the Credit Facility from $200.0 million to $400.0 million. The aggregate amount by which the Company may periodically increase commitments through incremental facilities is $100.0 million, the sublimit for letters of credit is $200.0 million and the sublimit for swing line loans is $25.0 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 of 0.5% on the unused portion of the Credit Facility.

As of December 31, 2013, $150.0 million was outstanding under the Credit Facility, along with $0.7 million in letters of credit, leaving $249.3 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, 2013 was 2.4%.

The Credit Facility contains customary affirmative and restrictive covenants including financial reporting, governance and notification requirements. Among other restrictions, the Company is unable to issue dividends under the terms of the Credit Facility. The Company was in compliance with all debt covenants under the Credit Facility as of December 31, 2013.

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 a “build-to-suit” lease agreement for the construction of its research and technology facility as well as its new corporate headquarters. The research and technology facility was completed during 2013, and is being accounted for as a capital lease, which is a non-cash investing and financing activity. The cost of the leased building was approximately $13.5 million and accumulated amortization was $0.1 million at December 31, 2013. 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 $15.7 million, of which approximately $2.4 million represents interest expense. Commencement of the corporate headquarters lease will begin when construction of the facility is substantially complete, which is expected to be in April 2014.

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NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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.

Note 3 – Acquisitions

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 liabilities assumed	$	80,578
Net assets acquired	$	280,759

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

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO 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.”

On April 28, 2011, the Company acquired all of the outstanding common stock of Total E&S, Inc. (“Total Equipment”), one of its largest suppliers of hydraulic fracturing, coiled tubing and pressure pumping equipment. The aggregate purchase price of approximately $33.0 million included $23.0 million in cash to the sellers and $10.0 million in repayment of the outstanding debt and accrued interest of Total Equipment. In exchange for the consideration transferred, the Company acquired net working capital assets with an estimated value of approximately $6.9 million, including $5.4 million in cash and cash equivalents.

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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NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 – Income Taxes

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

	Years Ended December 31,
	2013			2012			2011
Current provision:
Federal	$	22,870		$	75,205		$	37,687
State		1,930			3,948			4,751
Total current provision		24,800			79,153			42,438
Deferred (benefit) provision:
Federal		14,864			16,199			45,039
State		1,705			(273	)		864
Foreign		(56	)		—			—
Total deferred provision		16,513			15,926			45,903
Provision for income taxes	$	41,313		$	95,079		$	88,341

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

	Years Ended December 31,
	2013			2012			2011
Federal statutory rate		35.0	%		35.0	%		35.0	%
State taxes, net of federal benefit		2.8	%		1.4	%		1.6	%
Domestic production activities deduction		–1.8	%		–2.6	%		–1.5	%
Effect of foreign losses		0.7	%		—			—
Other		1.7	%		0.5	%		0.2	%
Effective income tax rate		38.4	%		34.3	%		35.3	%

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NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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

	As of December 31,
	2013			2012
Deferred tax assets:
Accrued liabilities	$	635		$	2,877
Allowance for doubtful accounts		609			394
Stock-based compensation		335			—
Other		429			342
Current deferred tax assets		2,008			3,613
Stock-based compensation		14,577			10,370
Net operating losses		750			410
Accrued liabilities		93			—
Other		123			187
Non-current deferred tax assets		15,543			10,967
Total deferred tax assets		17,551			14,580
Valuation allowance		—			—
Total deferred tax assets, net		17,551			14,580
Deferred tax liabilities:
Current deferred tax liability		(286	)		—
Depreciation on property, plant and equipment		(113,584	)		(96,691	)
Amortization of goodwill and intangible assets		(47,174	)		(45,595	)
Other		—			(1,232	)
Non-current deferred tax liabilities		(160,758	)		(143,518	)
Net deferred tax liability	$	(143,493	)	$	(128,938	)

The Company has approximately $2.3 million of state net operating loss carryforwards (“NOL’s”) which expire in various years between 2024 and 2031. 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 2010 through 2012 remain open to examination under the applicable federal statute of limitations provisions. The Company’s Texas franchise tax returns for the years 2009 through 2012 remain open to examination under the applicable Texas statute of limitations provisions. None of the Company’s federal returns are currently under examination. The Company filed an amended Texas return for 2009 which is currently under examination.

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NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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.

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; stock appreciation rights; 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 generally 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 3.1 million shares were available for issuance under the 2012 LTIP as of December 31, 2013.

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

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generally granted with an exercise price equal to the market price of the Company’s stock at the grant date. Those option awards generally vest over three years of continuous service with one-third vesting on the first, second, and third anniversaries of the option’s grant date. Certain option awards provide for accelerated vesting if there is a change in control, as defined in the 2010 Plan. The options expire on the tenth anniversary of the date of grant.

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

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

Stock Options

The fair value of each option award granted under the 2012 LTIP and the Prior Plans is estimated on the date of grant using the Black-Scholes option-pricing model. Due to the Company’s lack of historical volume of option activity, the expected term of options granted is derived using the “plain vanilla” method. In addition, expected volatilities have been based on comparable public company data, with consideration given to the Company’s limited historical data. The Company makes estimates with respect to employee termination and forfeiture rates of the options within the valuation model. The risk-free rate is based on the approximate U.S. Treasury yield rate in effect at the time of grant. For options granted prior to the Company’s initial public offering (“IPO”), which closed on August 3, 2011, the calculation of the Company’s stock price involved the use of different valuation techniques, including a combination of an income and/or market approach. Determination of the fair value was a matter of judgment and often involved the use of significant estimates and assumptions. The following table presents the assumptions used in determining the fair value of option awards for the years ended December 31, 2012 and 2011. No stock options were granted by the Company for the year ended December 31, 2013.

	Years Ended December 31,
	2012	2011
Expected volatility	65% - 75%	75.0%
Expected dividends	None	None
Exercise price	$16.88 - $18.89	$10.00 - $29.00
Expected term (in years)	6	5 - 6
Risk-free rate	0.9% - 1.4%	1.1% - 2.6%

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The weighted average grant date fair value of options granted during the years ended December 31, 2012 and 2011 was $11.45 and $15.30, respectively.

A summary of the Company’s stock option activity for the year ended December 31, 2013 is presented below.

	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
	(in thousands)					(in years)		(in thousands)
Outstanding at January 1, 2013		6,266		$	11.06
Granted		—			—
Exercised		(877	)		5.96
Forfeited		(106	)		21.98
Outstanding at December 31, 2013		5,283		$	11.69		6.36	$	65,351
Exercisable at December 31, 2013		4,809		$	10.59		6.23	$	63,680

The total intrinsic value of options exercised during the years ended December 31, 2013 and 2012 was $13.0 million and $7.0 million, respectively. As of December 31, 2013, there was $4.3 million of total unrecognized compensation cost related to outstanding stock options. That cost is expected to be recognized over a weighted-average period of 0.7 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, 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. During the year ended December 31, 2012, approximately 0.8 million shares of restricted stock were granted to employees, consultants and non-employee directors under the 2012 LTIP at fair market values ranging from $18.01 to $20.89 per share.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

A summary of the status and changes during the year ended December 31, 2013 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, 2013		748		$	18.94
Granted		746			23.37
Forfeited		(77	)		20.46
Vested		(284	)		19.40
Non-vested at December 31, 2013		1,133		$	21.63

As of December 31, 2013 and 2012, respectively, there was $15.8 million and $10.5 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 1.9 years. The weighted-average grant-date fair value per share of restricted stock granted during the years ended December 31, 2013 and 2012, respectively, was $23.37 and $18.93.

As of December 31, 2013, the Company had 6.4 million 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. As of December 31, 2012, the Company had 7.0 million of stock options and shares of restricted stock outstanding to employees and non-employee directors, 1.6 million of which were issued under the 2006 Plan, 4.6 million were issued under the 2010 Plan and the remaining 0.8 million were issued under the 2012 Plan.

Stock-based compensation expense was $22.6 million, $18.0 million and $10.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. The total income tax benefit recognized in the consolidated statements of operations in connection with stock-based compensation expense was approximately $7.9 million, $6.2 million and $3.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Note 7 – Related Party Transactions

The Company has historically purchased a significant portion of machinery and equipment from Total Equipment who, prior to April 28, 2011, was 12% owned by the Company’s chief executive officer. As discussed in Note 3 – Acquisitions, on April 28, 2011 the Company acquired 100% of the outstanding common stock of Total Equipment. For the period from January 1, 2011 to April 27, 2011, purchases from Total Equipment were $26.4 million.

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, 2013, 2012 and 2011, purchases from these vendors totaled $3.7 million, $2.6 million and $5.7 million, respectively. Amounts payable to these vendors at December 31, 2013 and 2012 were $0.1 million and $0.6 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. For the years ended December 31, 2013, 2012 and 2011, purchases from these vendors were $3.8 million, $14.7 million and $8.1 million, respectively. Amounts payable to these vendors at December 31, 2013, 2012 and 2011 were $0.9 million, $47,000 and $0.7 million, respectively.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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, 2013 and 2012, purchases from these vendors were $1.7 million and $1.3 million, respectively, and amounts payable to these vendors at December 31, 2013 and 2012 were $50,700 and $0.3 million, respectively. There were no related party transactions affiliated with any of the Company’s employees for the year ended December 31, 2011.

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 year ended December 31, 2013, purchases from this vendor were $7.6 million.

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

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 64.6%, 81.0% and 92.7% of the Company’s consolidated revenue for the years ended December 31, 2013, 2012 and 2011, respectively. For the year ended December 31, 2013, revenue from two customers individually represented 19.5% and 13.1%, respectively, of the Company’s consolidated revenue. For the year ended December 31, 2012, revenue from three customers individually represented 19.1%, 15.6% and 12.9%, respectively, of the Company’s consolidated revenue. For the year ended December 31, 2011, revenue from five customers individually represented 23.1%, 18.2%, 15.9%, 13.2% and 10.4%, respectively, of the Company’s consolidated revenue. Other than those listed above, no other customer accounted for more than 10% of the Company’s consolidated revenue in 2013, 2012 or 2011, respectively. Revenue is 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.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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 $12.2 million as of December 31, 2013. The Company expects to fulfill these commitments during 2014.

Operating Leases

The Company leases certain property and equipment under non-cancelable operating leases. The term of the operating leases generally range from 12 months to 15 years.

Lease expense under all operating leases totaled $ 14.6 million, $12.3 million and $5.5 million for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, the future minimum lease payments under non-cancelable operating leases were as follows (in thousands):

Years Ending December 31,
2014	$	9,130
2015		5,228
2016		3,828
2017		2,494
2018		1,903
Thereafter		6,822
	$	29,405

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

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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, 2013, 2012 and 2011 totaled $1.9 million, $1.0 million and $0.3 million, respectively.

Note 11 - Segment Information

In accordance with FASB ASC 280Segment 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. Prior to the acquisition of Casedhole Solutions on June 7, 2012, the Company operated under two segments: Stimulation and Well Intervention Services and Equipment Manufacturing. The Company analyzed the impact of the Casedhole Solutions acquisition on its operations and determined that, as a result thereof, a third reportable segment now exists–the Wireline Services segment. The following is a brief description of the Company’s three segments:

Stimulation and Well Intervention Services. This segment has three related service lines providing hydraulic fracturing coiled tubing and other well stimulation services. Additionally, with the development of the specialty chemicals business and strategic acquisitions during 2013, the Company now provides specialty chemicals for completion and production services, as well as downhole tools and related directional drilling technology and data control systems. After an evaluation of these businesses, it was determined that at this time each is appropriately accounted for under the Stimulation and Well Intervention Services segment.

Wireline Services. This segment provides cased-hole wireline services and other complementary services, including logging, perforating, pipe recovery, pressure testing and pumpdown services.

Equipment Manufacturing. This segment constructs equipment, conducts equipment repair services 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.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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, 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	$	644,222	$	399,999	$	80,426		$	7,653		$	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		6,227		—		68,869			(75,096	)		—
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
Year ended December 31, 2011							��
Revenue from external customers	$	736,391	$	—	$	22,063		$	—		$	758,454
Inter-segment revenues		—		—		51,964			(51,964	)		—
Adjusted EBITDA		310,078		—		13,203			(37,893	)		285,388
Depreciation and amortization		20,248		—		2,700			(29	)		22,919
Operating income (loss)		289,887		—		10,510			(38,211	)		262,186
Capital expenditures		142,997		—		2,442			(4,716	)		140,723
As of December 31, 2011
Total assets	$	486,278	$	—	$	60,942		$	(9,371	)	$	537,849
Goodwill		60,339		—		4,718			—			65,057

Revenue by service line for the Stimulation and Well Intervention Services segment for the years ended December 31, 2013, 2012 and 2011 was as follows (in thousands):

	Years Ended December 31,
Service Line	2013		2012		2011
Hydraulic fracturing	$	626,297	$	784,923	$	619,772
Coiled tubing and other well stimulation		157,111		155,335		116,619
Total revenue	$	783,408	$	940,258	$	736,391

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, including loss on early extinguishment of debt and loss on legal settlement charges and inventory write-down (“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

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2013			2012			2011
Adjusted EBITDA	$	190,674		$	336,712		$	285,388
Interest expense, net		(6,550	)		(4,996	)		(4,221	)
Provision for income taxes		(41,313	)		(95,079	)		(88,341	)
Depreciation and amortization		(74,703	)		(46,912	)		(22,919	)
Gain (loss) on disposal of assets		(527	)		(692	)		25
Transaction costs		(306	)		(833	)		(348	)
Legal settlement		—			(5,850	)		—
Inventory write-down		(870	)		—			—
Loss on early extinguishment of debt		—			—			(7,605	)
Net income	$	66,405		$	182,350		$	161,979

Note 12 – IPO

On July 28, 2011, the Company’s registration statement on Form S-1 (Registration Statement No. 333-173177) relating to its IPO of 13,225,000 shares of its common stock was declared effective by the Securities and Exchange Commission (“SEC”). The IPO closed on August 3, 2011, at which time the Company issued and sold 4,300,000 shares and the selling stockholders named in the final prospectus sold 8,925,000 shares, including 1,725,000 shares sold by certain of the selling stockholders pursuant to the full exercise of the underwriters’ option to purchase additional shares. The Company received cash proceeds of approximately $112.1 million from this transaction, net of underwriting discounts, commissions and transaction fees. The Company did not receive any proceeds from the sale of shares by the selling stockholders.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Note 13 – Quarterly Financial Data (unaudited)

Summarized quarterly financial data for the years ended December 31, 2013 and 2012 are presented below (in thousands, except per share amounts).

	Quarters Ended
					September		December
	March 2013		June 2013		2013		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		25,144		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

	Quarters Ended
					September		December
	March 2012		June 2012		2012		2012
Revenue	$	239,052	$	278,388	$	307,797	$	286,264
Operating income		75,962		82,066		74,923		49,579
Income before income taxes		75,510		81,175		72,955		47,789
Net income		49,379		53,275		49,266		30,430
Net income per common share:
Basic	$	0.95	$	1.03	$	0.95	$	0.58
Diluted	$	0.92	$	0.99	$	0.91	$	0.56

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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, 2013.

Management’s Report Regarding Internal Control.Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of its Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.As of December 31, 2013, management,including the Company’s Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of its internal control over financial reporting. Based on their assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2013. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management’s report on internal control over financial reporting is included on page 56 of this Form 10-K.

UHY LLP, the Company’s independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2013. Their report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013, is included on page 58 of this Form 10-K.

Changes in Internal Controls over Financial Reporting.There have been no changes in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference to our definitive proxy statement for our 2014 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act. We expect to file the definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.

Item 11. Executive Compensation

The information required by this item is incorporated by reference to our definitive proxy statement for our 2014 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act. We expect to file the definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.

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

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth certain information regarding our equity compensation plans as of December 31, 2013.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (A)		Weighted-average exercise price of outstanding options, warrants and rights (B)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in Column (A)) (C)
Equity compensation plans approved by security holders(1)		5,282,340	$	11.69		3,131,535
Equity compensation plans not approved by security holders		—		—		—
Total		5,282,340	$	11.69		3,131,535

⁽¹⁾ Consists of (i) 1,132,518 non-qualified stock options issued and outstanding under the C&J Energy Services, Inc. 2006 Stock Option Plan (the “2006 Plan”), (ii) 4,076,056 non-qualified stock options issued and outstanding under the C&J Energy Services, Inc. 2010 Stock Option Plan (the “2010 Plan”) and (iii) 73,766 non-qualified stock options issued and outstanding under the C&J Energy Services, Inc. Long-Term Incentive Plan (the “2012 LTIP”). There were also 1,132,883 shares of restricted stock issued and outstanding under the 2012 LTIP as of such date. On December 23, 2010, the 2006 Plan was amended to provide, among other things, that no additional awards will be granted under the 2006 Plan and on May 29, 2012, the 2010 Plan was amended to provide, among other things, that no additional awards will be granted under the 2010 Plan. Pursuant to the terms of the 2006 Plan and the 2010 Plan, if and to the extent an award originally granted pursuant to the 2006 Plan or the 2010 Plan, as applicable, 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. See “Note 6 - Stock-Based Compensation” in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information regarding these stock options plans.

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The remaining information required by this item is incorporated by reference in our definitive proxy statement for our 2014 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.

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

The information required by this item is incorporated by reference to our definitive proxy statement for our 2014 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act. We expect to file the definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.

Item 14. Principal Accounting Fees and Services

The information required by this item is incorporated by reference to our definitive proxy statement for our 2014 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act. We expect to file the definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

Our Consolidated Financial Statements and accompanying footnotes are included under Part II, Item 8 “Financial Statements and Supplementary Data” of thisForm 10-K.

(a)(2) Financial Statement Schedules

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

(a)(3) Exhibits

The following documents are included as exhibits to this Form 10-K:

Exhibit No.	Description of Exhibit.
3.1	Amended and Restated Certificate of Incorporation of C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
3.2	Second Amended and Restated Bylaws of C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on February 29, 2012 (File No. 001-35225))
4.1	Form of Stock Certificate (incorporated herein by reference to Exhibit 4.1 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
4.2+	Form of Non-Statutory Stock Option Agreement for Certain Executive Officers with C&J Employment Agreements, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 21, 2012 (File No. 001-35255))
4.3+	Form of Non-Statutory Stock Option Agreement with Restrictive Covenants, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 21, 2012 (File No. 001-35255))
4.4+	Form of Non-Statutory Stock Option Agreement with Limited Covenants, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.5+	Form of Non-Statutory Stock Option Agreement for Certain Executive Officers with Assumed Employment Agreement, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.6+	Form of Non-Statutory Stock Option Agreement for Certain Executive Officers with New Employment Agreements, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.5 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))

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4.7+	Form of Non-Statutory Stock Option Agreement for Non-Employee Directors, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.8+	Form of Restricted Stock Agreement for Certain Executive Officers with C&J Employment Agreements, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 21, 2012 (File No. 001-35255))
4.9+	Form of Restricted Stock Agreement with Restrictive Covenants, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 21, 2012 (File No. 001-35255))
4.10+	Form of Restricted Stock Agreement with Limited Covenants, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.9 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.11+	Form of Restricted Stock Agreement for Certain Executive Officers with Assumed Employment Agreement, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.10 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.12+	Form of Restricted Stock Agreement for Certain Executive Officers with New Employment Agreements, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.11 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.13+	Form of Restricted Stock Agreement for Non-Employee Directors, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.12 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.14+	Form of Participation Agreement for C&J International Middle East FZCO Phantom Equity Arrangement under the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on December 19, 2013 (File No. 001-35255))
10.1+	C&J Energy Services, Inc. 2012 Long-Term Incentive Plan, effective as of April 5, 2012, adopted by the Board of Directors and approved by the Stockholders on May 29, 2012 (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 1, 2012))
10.2+	C&J International Middle East FZCO Phantom Equity Arrangement under the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on December 19, 2013 (File No. 001-35255))
10.3	Credit Agreement, dated as of April 19, 2011, among C&J Energy Services, Inc. as Borrower, Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, Comerica Bank as L/C Issuer and Syndication Agent, Wells Fargo Bank, National Association as Documentation Agent, and the Other Lenders party thereto (incorporated herein by reference to Exhibit 10.18 to Amendment No. 1 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))

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10.4	Amendment No. 1 and Joinder to Credit Agreement, dated as of June 5, 2012, by and among C&J Energy Services, Inc., the Lenders party thereto, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and solely for purposes of Section 8 thereof, the Guarantors named therein (incorporated by reference to Exhibit 10.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 7, 2012 (File No. 001-35255))
10.5	Stock Purchase Agreement, dated as of June 5, 2012, by and among C&J Spec-Rent Services, Inc., Casedhole Holdings, Inc., the shareholders of Casedhole Holdings, Inc. listed on the signature pages thereto, and the option holders of Casedhole Holdings, Inc. listed on the signature pages thereto (incorporated by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 7, 2012 (File No. 001-35255))
10.6+	Amended and Restated Employment Agreement effective December 23, 2010 between C&J Energy Services, Inc. and Joshua E. Comstock (incorporated herein by reference to Exhibit 10.7 to Amendment No. 2 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177))
10.7+	Amended and Restated Employment Agreement effective December 23, 2010 between C&J Energy Services, Inc. and Randall C. McMullen, Jr. (incorporated herein by reference to Exhibit 10.8 to Amendment No. 2 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177))
10.8+	Employment Agreement effective February 1, 2011 between C&J Energy Services, Inc. and Theodore R. Moore (incorporated herein by reference to Exhibit 10.10 to Amendment No. 2 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177))
10.9+	Executive Employment Agreement effective as of August 15, 2013 by and between C&J Energy Services, Inc. and Donald J. Gawick (incorporated herein by reference to Exhibit 10.1 to the C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on August 15, 2013 (File No. 001-35255))
10.10+	Executive Employment Agreement dated April 4, 2013 and effective as of April 1, 2013 by and between C&J Energy Services, Inc. and James H. Prestidge, Jr. (incorporated by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013 filed on May 5, 2013 (File No. 001-35255))
* 21.1	List of Subsidiaries of C&J Energy Services, Inc.
* 23.1	Consent of UHY LLP
* 31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
** 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002

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** 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
* §101.INS	XBRL Instance Document
** §101.SCH	XBRL Taxonomy Extension Schema Document
** §101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
** §101.LAB	XBRL Taxonomy Extension Label Linkbase Document
** §101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
** §101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith

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

+ Management contract or compensatory plan or arrangement

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, this 26^th day of February, 2014.

C&J Energy Services, Inc.
By:	/s/ Randall C. McMullen, Jr.
	Randall C. McMullen, Jr.
	President, Chief Financial Officer, Treasurer and Director (Principal Financial Officer)

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

Signatures and Capacities		Date
By:	/s/ Joshua E. Comstock	February 26, 2014
	Joshua E. Comstock, Chairman and Chief Executive Officer (Principal Executive Officer)
By:	/s/ Randall C. McMullen, Jr.	February 26, 2014
	Randall C. McMullen, Jr., President, Chief Financial Officer, Treasurer and Director (Principal Financial Officer)
By:	/s/ Mark C. Cashiola	February 26, 2014
	Mark C. Cashiola, Vice President and Controller (Principal Accounting Officer)
By:	/s/ Darren M. Friedman	February 26, 2014
	Darren M. Friedman, Director
By:	/s/ Adrianna Ma	February 26, 2014
	Adrianna Ma, Director
By:	/s/ Michael Roemer	February 26, 2014
	Michael Roemer, Director
By:	/s/ C. James Stewart III	February 26, 2014
	C. James Stewart III, Director
By:	/s/ H. H. “Tripp” Wommack, III	February 26, 2014
	H. H. “Tripp” Wommack, III, Director

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EXHIBIT INDEX

The following documents are included as exhibits to this Form 10-K.

Exhibit No.	Description of Exhibit.
3.1	Amended and Restated Certificate of Incorporation of C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
3.2	Second Amended and Restated Bylaws of C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on February 29, 2012 (File No. 001-35225))
4.1	Form of Stock Certificate (incorporated herein by reference to Exhibit 4.1 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
4.2+	Form of Non-Statutory Stock Option Agreement for Certain Executive Officers with C&J Employment Agreements, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 21, 2012 (File No. 001-35255))
4.3+	Form of Non-Statutory Stock Option Agreement with Restrictive Covenants, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 21, 2012 (File No. 001-35255))
4.4+	Form of Non-Statutory Stock Option Agreement with Limited Covenants, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.5+	Form of Non-Statutory Stock Option Agreement for Certain Executive Officers with Assumed Employment Agreement, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.6+	Form of Non-Statutory Stock Option Agreement for Certain Executive Officers with New Employment Agreements, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.5 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.7+	Form of Non-Statutory Stock Option Agreement for Non-Employee Directors, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.8+	Form of Restricted Stock Agreement for Certain Executive Officers with C&J Employment Agreements, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 21, 2012 (File No. 001-35255))
4.9+	Form of Restricted Stock Agreement with Restrictive Covenants, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 21, 2012 (File No. 001-35255))

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4.10+	Form of Restricted Stock Agreement with Limited Covenants, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.9 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.11+	Form of Restricted Stock Agreement for Certain Executive Officers with Assumed Employment Agreement, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.10 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.12+	Form of Restricted Stock Agreement for Certain Executive Officers with New Employment Agreements, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.11 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.13+	Form of Restricted Stock Agreement for Non-Employee Directors, pursuant to the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.12 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2012 (File No. 001-35255))
4.14+	Form of Participation Agreement for C&J International Middle East FZCO Phantom Equity Arrangement under the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on December 19, 2013 (File No. 001-35255))
10.1+	C&J Energy Services, Inc. 2012 Long-Term Incentive Plan, effective as of April 5, 2012, adopted by the Board of Directors and approved by the Stockholders on May 29, 2012 (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 1, 2012))
10.2+	C&J International Middle East FZCO Phantom Equity Arrangement under the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on December 19, 2013 (File No. 001-35255))
10.3	Credit Agreement, dated as of April 19, 2011, among C&J Energy Services, Inc. as Borrower, Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, Comerica Bank as L/C Issuer and Syndication Agent, Wells Fargo Bank, National Association as Documentation Agent, and the Other Lenders party thereto (incorporated herein by reference to Exhibit 10.18 to Amendment No. 1 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
10.4	Amendment No. 1 and Joinder to Credit Agreement, dated as of June 5, 2012, by and among C&J Energy Services, Inc., the Lenders party thereto, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and solely for purposes of Section 8 thereof, the Guarantors named therein (incorporated by reference to Exhibit 10.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 7, 2012 (File No. 001-35255))
10.5	Stock Purchase Agreement, dated as of June 5, 2012, by and among C&J Spec-Rent Services, Inc., Casedhole Holdings, Inc., the shareholders of Casedhole Holdings, Inc. listed on the signature pages thereto, and the option holders of Casedhole Holdings, Inc. listed on the signature pages thereto (incorporated by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 7, 2012 (File No. 001-35255))

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10.6+	Amended and Restated Employment Agreement effective December 23, 2010 between C&J Energy Services, Inc. and Joshua E. Comstock (incorporated herein by reference to Exhibit 10.7 to Amendment No. 2 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177))
10.7+	Amended and Restated Employment Agreement effective December 23, 2010 between C&J Energy Services, Inc. and Randall C. McMullen, Jr. (incorporated herein by reference to Exhibit 10.8 to Amendment No. 2 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177))
10.8+	Employment Agreement effective February 1, 2011 between C&J Energy Services, Inc. and Theodore R. Moore (incorporated herein by reference to Exhibit 10.10 to Amendment No. 2 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177))
10.9+	Executive Employment Agreement effective as of August 15, 2013 by and between C&J Energy Services, Inc. and Donald J. Gawick (incorporated herein by reference to Exhibit 10.1 to the C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on August 15, 2013 (File No. 001-35255))
10.10+	Executive Employment Agreement dated April 4, 2013 and effective as of April 1, 2013 by and between C&J Energy Services, Inc. and James H. Prestidge, Jr. (incorporated by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013 filed on May 5, 2013 (File No. 001-35255))
* 21.1	List of Subsidiaries of C&J Energy Services, Inc.
* 23.1	Consent of UHY LLP
* 31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
** 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
** 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
* §101.INS	XBRL Instance Document
** §101.SCH	XBRL Taxonomy Extension Schema Document
** §101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
** §101.LAB	XBRL Taxonomy Extension Label Linkbase Document
** §101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
** §101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

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* Filed herewith

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

+ Management contract or compensatory plan or arrangement

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