C&J Energy Services 10-K 2012 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, 2012.

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.  Yesx    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¨    Smaller reporting company ¨

                                                                              (Do not check if a 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¨    Nox

The aggregate market value of the registrant’s common stock held by non-affiliates on June 29, 2012 (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 $773.4 million.

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at February 22, 2013, was 54,004,877.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for its 2013 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2012, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		3
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		27
Item 2.	Properties		28
Item 3.	Legal Proceedings		29
Item 4.	Mine Safety Disclosures		29
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		30
Item 6.	Selected Financial Data		31
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		51
Item 8.	Financial Statements and Supplementary Data		53
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		85
Item 9A.	Controls and Procedures		85
Item 9B.	Other Information		85
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		86
Item 11.	Executive Compensation		86
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		86
Item 13.	Certain Relationships and Related Transactions, and Director Independence		87
Item 14.	Principal Accounting Fees and Services		87
PART IV
Item 15.	Exhibits, Financial Statement Schedules		87
	Signatures		92

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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 revenues, income and operating performance;

• our ability to sustain and improve our margins;

• operating cash flows and availability of capital;

• the timing and success of future acquisitions and other 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, the following, as well as those factors described in Part I, Item 1A “Risk Factors” and in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K:

• a sustained decrease in domestic spending by the oil and natural gas exploration and production industry;

• a decline in or substantial volatility of crude oil and natural gas commodity prices;

• the loss of or interruption in operations of one or more key suppliers;

• overcapacity and competition in our industry;

• increased pressures on pricing due to competition and economic conditions;

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• the incurrence of significant costs and liabilities in the future 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;

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

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

• unanticipated 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;

• a shortage of qualified workers;

• operating hazards inherent in our industry;

• accidental damage to or malfunction of equipment;

• an increase in interest rates;

• the potential inability to comply with the financial and other covenants in our debt agreements as a result of reduced revenues 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; and

• the potential failure to establish and maintain effective internal control over financial reporting.

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

Our Business

C&J Energy Services, Inc., a Delaware corporation, was founded in Texas in 1997. On July 29, 2011 we began trading on the New York Stock Exchange (“NYSE”) under the symbol “CJES.”

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. We also manufacture and repair equipment to fulfill our internal needs and for third-party companies in the energy services industry. We operate in three reportable segments: Stimulation and Well Intervention Services, Wireline Services and Equipment Manufacturing. We provide hydraulic fracturing, coiled tubing and related well intervention services through our Stimulation and Well Intervention Services segment to oil and natural gas exploration and production companies operating in some of the most geologically challenging and active formations in the United States. Subsequent to our June 7, 2012 acquisition of Casedhole Holdings, Inc. (together with its operating subsidiary, Casedhole Solutions, Inc., “Casedhole Solutions”), we provide cased-hole wireline and other complementary services through our Wireline Services segment. The acquisition of Casedhole Solutions provided us with an expanded geographic presence in areas where we previously did not operate, such as the Williston and Uinta basins and the Marcellus, Utica, Avalon and Bone Springs shale formations. We are evaluating additional opportunities with existing and new customers to expand our Stimulation and Well Intervention Services and Wireline Services into new areas throughout the United States and internationally. Through our Equipment Manufacturing segment, which we added with the acquisition of Total E&S Inc. (“Total”) in April 2011, we manufacture and repair equipment and provide oilfield parts and supplies for companies in the energy services industry. Through Total, we fulfill our internal equipment demands and have centralized company-wide inventory management. Our three segments are described in more detail under “Our Operating Segments”. As used herein, references to the “Company” or “C&J” are to C&J Energy Services, Inc. together with its consolidated subsidiaries.

Our principal executive offices are 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

Prior to the acquisition of Casedhole Solutions on June 7, 2012, we had two operating segments: Stimulation and Well Intervention Services and Equipment Manufacturing. Upon the acquisition of Casedhole Solutions, we reevaluated our business and concluded that a third reportable segment exists: the Wireline Services segment. Our three segments are described in more detail below. For financial information about our segments, including revenues from external customers and total assets by segment, see “Note 11 – Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data.”

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Stimulation and Well Intervention Services

Our Stimulation and Well Intervention Services segment provides hydraulic fracturing and coiled tubing and other well intervention 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 pumped into the fractures created by the fracturing process in the underground formation 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 contributed $784.9 million to our revenue for the year ended December 31, 2012 and completed 6,243 fracturing stages during the year ended December 31, 2012.

Coiled Tubing.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. 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. Our coiled tubing operations contributed $140.2 million to our revenue for the year ended December 31, 2012, and we completed 3,719 coiled tubing jobs during the year ended December 31, 2012. Our coiled tubing operations also perform other well stimulation services including pumpdown services for wireline and coiled tubing. For the year ended December 31, 2012, we generated $15.2 million of revenue from these services.

Wireline Services

We commenced our Wireline Services segment with the acquisition of Casedhole Solutions on June 7, 2012. See “Note 4 – 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 contributed $130.1 million of revenue from the date of the acquisition through December 31, 2012.

Equipment Manufacturing

Our Equipment Manufacturing segment constructs oilfield equipment, including hydraulic fracturing pumps, coiled tubing units, pressure pumping units and other equipment for our Stimulation and Well Intervention Services and Wireline Services segments as well as for third-party customers in

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the energy services industry. This segment also provides equipment repair services and oilfield parts and supplies to the energy services industry, and to meet our own internal needs. Our Equipment Manufacturing segment contributed $41.1 million in third-party revenue for the year ended December 31, 2012.

Our Industry 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 we have taken steps to mitigate them to the extent practicable. In addition, while we believe that we are well positioned to capitalize on available growth opportunities, we may not be able to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read this section in conjunction with the factors described in “Cautionary Note Regarding Forward-Looking Statements”, Part I, Item 1A “Risk Factors” and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K.

Our business depends on the capital spending programs of our customers. Our Stimulation and Well Intervention Services and Wireline Services segments are significantly driven by the exploration, development and production expenditures made by our customers, which also impacts sales by our Equipment Manufacturing segment to third-party customers in the energy services industry. These customers have historically tended to delay capital equipment projects, including maintenance and upgrades, during industry downturns. 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, including the current and expected future prices for oil and gas, and the perceived stability and sustainability of those prices, as well as production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling and workover budgets.

Trends which we believe are affecting, and will continue to affect, our industry include:

Ongoing Development of Existing and Emerging Unconventional Resource Basins. Over the past decade, exploration and production companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays, such as oil and natural gas shales. Two technologies that are critical to the recovery of oil and natural gas from unconventional resource plays are horizontal drilling and hydraulic fracturing. Horizontal drilling is used to provide greater access to the hydrocarbons trapped in the producing formation by exposing the well to more of the producing formation. Hydraulic fracturing unlocks the hydrocarbons trapped in formations by opening fractures in the rock and allowing hydrocarbons to flow from the formation into the well. We believe long-term capital for the continued development of these basins will be provided in part by the participation of large well-capitalized domestic oil and gas companies that have made significant investments, as well as international oil and gas companies that continue to make significant capital commitments through joint ventures and direct investments in North America’s unconventional resource basins. We believe these investments indicate a long-term commitment to development, and that the service-intensive nature of completion activities in unconventional resource formations will have a positive long-term impact on demand for the types of services we offer. However, we remain concerned about the migration of drilling activity and overcapacity of completion equipment in the oily- and liquids-rich regions from the gassier regions and the weakness in the price of natural gas and natural gas liquids, as this has continued to increase competition among oilfield service companies and has negatively affected the spot market pricing for some of our services.

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Increased Horizontal Drilling and Greater Service Intensity in Unconventional Resource Basins. The development of unconventional drilling environments requires more complex, technically demanding completion jobs than conventional drilling activity. We believe exploration and production companies have shown a preference for a customized approach to completing complex wells in unconventional resource basins. Even with the increasing completion capacity, particularly with respect to hydraulic fracturing equipment, we believe that, over the long term, the required attention and experience to complete the most difficult fracturing jobs in these service-intensive basins will continue to have a positive long-term impact on demand for the types of services that we offer. As a result of the higher specification equipment and increased service intensity associated with horizontal drilling, we view the U.S. horizontal rig count as a reliable indicator of the overall level of demand for our services and products. The increased level of horizontal drilling, which has largely targeted unconventional resource plays, is illustrated by the growing number of horizontal rigs active in the United States over the past three years. According to Baker Hughes Incorporated, the U.S. horizontal rig count has risen from approximately 335 at the beginning of 2007 to 1,140 as of February 22, 2013, and as of such date represented 64.7% of the total U.S. rig count. In addition, we have witnessed horizontal wells becoming longer and more complex, resulting in an increase in the number of fracturing stages, and amount of horsepower and proppant and chemicals used per well. Furthermore, we believe operators have become more efficient at drilling horizontal wells and have reduced the number of days required to reach total depth, which has increased the number of wells drilled and therefore the number of fracturing stages completed in a year. As we see additional hydraulic fracturing equipment enter the markets through both industry veterans and start-up companies, we believe that technical expertise, fleet capability and experience will remain as the primary differentiating factors within the industry.

Enhanced Economics in Oily- and Liquids-Rich Formations. There is increasing horizontal drilling and completion related activity in oily- and liquids-rich formations such as the Eagle Ford Shale, Permian Basin, Granite Wash, Utica Shale, Bakken Shale and Niobrara Shale. We believe that the oil and liquids content in these plays significantly enhance the returns for our customers relative to opportunities in dry gas basins due to the significant disparity between oil and natural gas prices on a British thermal units (“Btu”) basis. Further, based on industry data, we believe the price disparity will continue over the near to mid-term resulting in increasing demand for the types of services that we offer in the unconventional formations with oily- and liquids-rich content. We expect to continue to benefit from increased horizontal drilling and completion-related activity in those complex unconventional formations, even with the migration of drilling and completion capacity from the gassier regions.

The Spread of Unconventional Drilling and Completion Techniques to the Redevelopment of Conventional Fields. Oil and natural gas companies have begun to apply the knowledge gained through the extensive development of unconventional resource plays to their existing conventional basins. Many of the techniques applied in unconventional development, when applied to conventional wells either through workover or recompletion, have the potential to enhance overall production or enable production from previously unproductive regions and improve overall field economics. We continue to believe that there are many older conventional wells with the potential for the application of unconventional completion techniques in close proximity to the regions in which we operate. Many of our customers have begun to experiment with such techniques.

Financial Information About Geographic Areas

During the three year period ended December 31, 2012, all of our revenues from external customers were derived from the United States, and all of our long-lived assets were located in the United States.

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Seasonality

Our results of operations have not historically reflected significant seasonal tendencies, however, during the fourth quarter of 2012 we experienced an atypical seasonal slowdown, particularly around the holidays, which negatively impacted utilization. We currently do not believe that seasonal fluctuations will have a material impact on our Stimulation and Well Intervention Services, Wireline Services or Equipment Manufacturing segments in the foreseeable future.

Sales and Marketing

Our sales and marketing activities relating to our Stimulation and Well Intervention Services and Wireline Services typically are 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 addition of Casedhole Solutions in June 2012, we are leveraging our wireline services to expand our customer base and geographic presence for our other services. In many cases, our initial successful work with our customers in one particular basin has led to additional work in other resource positions in which the customer operates. Additionally, our ability to provide services in the spot market has allowed us to develop new customers. We will continue to focus on leveraging our existing customer base and establishing new relationships with additional operators in order to selectively expand our operations into new basins.

Our Equipment Manufacturing segment manufactures equipment and provides equipment repair services and parts and supplies to oilfield services companies throughout the United States. C&J historically has been, and continues to be, one of Total’s top customers. During 2012 we increased Total’s manufacturing capabilities and brought on-line an additional 36,000 square foot manufacturing facility, which we began constructing in 2011. This expansion enhances our research and development efforts around equipment and innovation as we seek to further streamline our manufacturing capabilities and lower our equipment costs. We also recently added a 123,200 square foot warehouse for centralized company-wide inventory management.

Customers

The majority of our revenues are generated from our fracturing services, which are primarily provided to independent oil and natural gas exploration and production companies. For the year ended December 31, 2012, revenues from Anadarko Petroleum, Apache Corporation and Plains Exploration represented 19.1%, 15.6% and 12.9%, respectively, of our consolidated revenues. For the year ended December 31, 2011, sales to Anadarko Petroleum, Penn Virginia, EOG Resources, Plains Exploration and EXCO Resources represented 23.1%, 18.2%, 15.9%, 13.2% and 10.4%, respectively, of our total sales. In 2010, revenues from EOG Resources, Penn Virginia, Anadarko Petroleum and Apache Corporation accounted for 32.5%, 18.1%, 16.4% and 9.7%, respectively, of our consolidated revenues.

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Our top ten customers accounted for approximately 81.0%, 92.7% and 90.2% of our consolidated revenues for the years ended December 31, 2012, 2011 and 2010, respectively. Due to the large percentage of our revenues derived from our fracturing services and the limited number of fracturing fleets we possess, our customer concentration has historically been high. We believe our efforts to increase the number of fracturing fleets we operate has allowed us to serve a larger number of customers and will continue to reduce customer concentration.

The customers served through our Equipment Manufacturing segment are primarily oilfield services companies. C&J historically has been, and continues to be, one of Total’s top customers. Since 2010, Total has constructed almost all of our hydraulic fracturing equipment. Total has also constructed all of our coiled tubing and related ancillary equipment since 2004. Our Equipment Manufacturing segment did not generate a significant portion of our consolidated revenues for the year ended December 31, 2012.

Competition and Demand for Our Services

The markets in which we provide our Stimulation and Well Intervention Services and Wireline Services are highly competitive. We provide our services and products across the United States, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield 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 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 Baker Hughes. We believe that the principal competitive factors in the market areas that we serve are technical expertise, fleet capability and experience. While we must be competitive in our pricing, we believe our customers select our services and products based on a high level of technical expertise, superior customer service and shale knowledge that our personnel use to deliver quality services and products.

There is increasing horizontal drilling- and completion-related activity in oily- and liquids-rich formations due to the significant disparity between oil and natural gas prices on a Btu basis. Further, based on industry data, we believe the price disparity will continue over the near to mid-term resulting in increasing demand for the types of services that we offer in the unconventional formations with oily- and liquids-rich content. The development of unconventional drilling environments requires more complex, technically demanding completion jobs than conventional drilling activity. We believe that the service-intensive nature of completion activities in unconventional resource formations, in which we have a growing presence, will have a positive long-term impact on demand for our services. However, we remain concerned about the migration of drilling activity and completion capacity into the oily- and liquids-rich regions from the gassier regions and the weakness in the price of natural gas and natural gas liquids, as this has continued to increase competition among oilfield service companies in the oily regions and has negatively affected the spot market pricing for some of our services. See “Our Industry and Outlook” for further discussion.

In our Equipment Manufacturing segment, we compete 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 products, our major

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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 the materials used in our Stimulation and Well Intervention Services and Wireline Services segments, such as proppants, fluids, coiled tubing and other materials and supplies, from various suppliers. We have established relationships with a limited number of suppliers of our raw materials and finished products. In general, we believe that we will be able to make satisfactory alternative arrangements in the event of interruption of supply. Should any of our current suppliers be unable to provide the necessary raw materials (such as proppant, guar, fracturing fluids or coiled tubing) or finished products (such as fluid-handling equipment) 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. During the year ended December 31, 2012, we purchased 5% or more of our materials or equipment from each of Economy Polymers & Chemicals, PfP Technology and Santrol. During the year ended December 31, 2011, we purchased 5% or more of our materials or equipment from each of Economy Polymers & Chemicals and Total (now in our Equipment Manufacturing segment).

With respect to our Equipment Manufacturing segment, in 2012 approximately 91.4% of our costs of goods sold consisted of raw materials and component parts, with the other 8.6% being labor and overhead. We currently depend on a limited number of suppliers for certain important raw materials and components parts for our products. In general, we believe that we will be able to make satisfactory alternative arrangements in the event of interruption of supply. During the year ended December 31, 2012, one of our vendors, Holt Caterpillar, accounted for 24% of our raw materials and component parts purchases by our Equipment Manufacturing segment. During the year ended December 31, 2011, two of our vendors, Holt Caterpillar and Weir SPM, accounted for 19% and 16%, respectively, of our raw materials and component parts purchases by our Equipment Manufacturing segment.

Please see Part III, Item 13 “Certain Relationships and Related Party Transactions, and Director Independence — Supplier Agreements” for additional information regarding our related-party suppliers.

Safety

Our record and reputation for safety is important to all aspects of our business. In the oilfield services industry, an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced and skilled work force. In recent years, many of our larger customers have placed an emphasis not only on pricing, but also on safety records and quality management systems of contractors. We believe that these factors will gain further importance in the future. We have directed substantial resources toward employee safety and quality management training programs, as well as our employee review process.

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;

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• 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.

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

We maintain general liability insurance coverage of types and amounts that we believe to be customary in the industry, including sudden and accidental pollution insurance. Our sudden and accidental pollution insurance coverage is currently included under general liability, consisting of $1.0 million for each occurrence underlying coverage, $10.0 million for each occurrence umbrella coverage and additional excess coverage of $90.0 million 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 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

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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.

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, 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 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.

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

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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 numerous 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, assessment of administrative and civil penalties, and even criminal prosecution. We believe that we are in substantial compliance with applicable environmental laws and regulations. Further, we do not anticipate that compliance with existing environmental laws and regulations will have a material effect on our financial condition or results of operations. It is possible, however, that substantial costs for compliance or penalties for non-compliance may be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations, and enforcement policies, could result in additional costs or liabilities that we cannot currently quantify.

We generate wastes, including hazardous wastes, which are subject to the federal Resource Conservation and Recovery Act, as amended (“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. Some oil and natural gas exploration and production wastes handled by us in our field service activities currently are exempt from regulation as hazardous wastes. There is no guarantee, however, that the EPA or individual states will not adopt more stringent requirements for the handling of nonhazardous waste or categorize some nonhazardous waste as hazardous in the future. For instance, in September 2010, the Natural Resources Defense Council filed a petition for rulemaking with the EPA requesting reconsideration of the continued application of this RCRA exclusion but, to date, the EPA has not taken any action on the petition. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

The federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“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 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

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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 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.

In the course of our operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials (“NORM”). NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the properties presently or previously owned, operated, or occupied by us have been used for oil and natural gas related operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM.

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. In addition, 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.

Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study

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includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and waste water treatment and disposal. The EPA has indicated that it expects to issue its study report in late 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and the U.S. Department of the Interior is evaluating various aspects of hydraulic fracturing on federal lands. As part of several of these studies and reviews, some agencies and committees have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process and other information regarding hydraulic fracturing operations. These studies, depending on their results, could spur initiatives to further regulate hydraulic fracturing. Legislation has been introduced before Congress from time to time to provide for federal regulation of hydraulic fracturing and to require public disclosure of the chemicals used in the fracturing process. If this or similar federal legislation becomes law in the future, the legislation could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and doing business.

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.

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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 wellsite 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.

Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act, as amended (“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 more stringent 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 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.

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.

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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. 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.

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.

Employees

As of February 22, 2013, we had 1,989 employees. We anticipate hiring additional employees as we expand our service lines and undertake other large projects. Subject to local market conditions, additional crew members are generally available for hire on relatively short notice. Our employees are not represented by any labor unions. We consider our relations with our employees to be good.

Item 1A. Risk Factors

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 depends on the oil and natural gas industry and particularly on the level of exploration, development and production of oil and natural gas in the United States. Our markets may be adversely affected by industry conditions that are beyond our control.

We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas in the United States. If these expenditures decline,

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our business may suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which our management has no control, such as:

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

• the prices, and expectations about future prices, of oil and natural gas;

• 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 rates of new oil and natural gas reserves;

• available pipeline and other transportation capacity;

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

• political instability in oil and natural gas producing countries;

• domestic and worldwide economic conditions;

• technical advances affecting energy consumption;

• the price and availability of alternative fuels; and

• merger and divestiture activity among oil and natural gas producers.

The level of activity in the oil and natural gas exploration and production industry in the United States is volatile. The Henry Hub spot price for natural gas averaged $2.75, $4.00 and $4.37 per mcf (or one thousand cubic feet) in 2012, 2011 and 2010, respectively. The Cushing WTI Spot Oil Price averaged $94.05, $94.88 and $79.48 per barrel in 2012, 2011 and 2010, respectively. As of February 22, 2013, the Henry Hub spot price for natural gas was $3.02 per mcf and the Cushing WTI Spot Oil Price was $93.13 per barrel. Unexpected material declines in oil and natural gas prices, or drilling or completion activity in the U.S. oil and natural gas shale regions, could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, a decrease in the development rate of oil and natural gas reserves in our market areas may also have an adverse impact on our business, even in an environment of stronger oil and natural gas prices.

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The cyclicality of the oil and natural gas industry in the United States may cause our operating results to fluctuate.

We have experienced in the past, and may experience in the future, significant fluctuations in operating results as a result of the reactions of our customers to actual and anticipated changes in oil and natural gas prices in the United States. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could result in lower demand for our services and products and may cause lower rates and lower utilization of our well service equipment. If oil prices decline or natural gas prices continue to remain low or decline further, or if there is a reduction in drilling activities, the demand for our services and products and our results of operations could be materially and adversely affected.

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 oilfield services industry generally. The declines in natural gas prices during 2012 resulted in reduced drilling activity in natural gas shale plays, which drove oilfield 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 has 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.

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 and finished products. Should any of our current suppliers be unable to provide the necessary raw materials (such as proppant, guar, chemicals or coiled tubing) or finished products (such as fluid-handling equipment) 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.

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.

The SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel are subject to regulation under

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the UIC program, specifically as “Class II” UIC wells. 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. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on 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 waste water treatment and disposal. The EPA has indicated that it expects to issue its study report in late 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and the U.S. Department of the Interior is evaluating various aspects of hydraulic fracturing on federal lands. As part of several of these studies and reviews, some agencies and committees have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process and other information regarding hydraulic fracturing operations. These studies, depending on their results, could spur initiatives to further regulate hydraulic fracturing. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require public disclosure of the chemicals used in the fracturing process. If similar federal legislation is introduced and becomes law in the future, the legislation could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and doing business.

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 disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. This legislation and any implementing regulation 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 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

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Board. 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.

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

The majority of our revenues are generated from our fracturing services. Due to the large percentage of our revenues derived from our fracturing services and the limited number of fracturing fleets we possess, our customer concentration has historically been high. Our top five customers accounted for approximately 63.7%, 80.7% and 81.0% of our consolidated revenues for the years ended December 31, 2012, 2011 and 2010, respectively. Our top ten customers represented approximately 81.0%, 92.7% and 90.2% of our consolidated revenues for the years ended December 31, 2012, 2011 and 2010, 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.

We may not be able to renew our term contracts on attractive terms or at all, which could adversely impact our results of operations, financial condition and cash flows.

For the year ended December 31, 2012, we derived 55.0% of our consolidated revenues from term contracts. One of our term contracts expired in January 2013, although we have a strong relationship with this customer and negotiated a new agreement for continued work through the first half of 2013 at a pricing discount of approximately 20% from the previous contracted rates. Three of our hydraulic fracturing fleets are currently working under term contracts, two of which are set to expire in mid-2013 and one of which is set to expire in early 2014. The terms of these contracts typically range from one to three years. We may not be able to extend any of our current term contracts, enter into additional term contracts on favorable terms or at all, or deploy our hydraulic fracturing fleets in the spot market on attractive terms. If we are not able to do so, our results of operations, financial condition and cash flows could be materially adversely impacted.

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, 2012, our net income increased $181.4 million from $1.1 million to $182.5 million and our revenues increased $1.0 billion 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 are expected 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.

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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, including our acquisition of Casedhole Solutions in June 2012, 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.

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 revenues.

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

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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 months. 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, was increased from $200.0 million as a result of an amendment entered into on June 5, 2012 (“Credit Facility”), contains restrictive covenants and requires us to maintain a debt coverage ratio, to maintain a fixed charge coverage ratio and to satisfy other financial condition tests. Our ability to meet those financial requirements can 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 $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. 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” in Part II, Item 8 “Financial Statements and Supplementary Data.”

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Failure to maintain effective internal control over financial reporting could have a material adverse effect on our business, operating results and the trading price of our common stock.

As a public company, we are required to comply with Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which requires our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. In connection with this Form 10-K, we are required to make our first assessment of our internal control over financial reporting. Following the completion of our IPO in August 2011, we upgraded our systems, including information technology, implemented additional financial and management controls, reporting systems and procedures and hired additional accounting, finance and legal staff.

Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanctions or investigations by the SEC, the NYSE, or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

Weather conditions could materially impair our business.

Our operations may be adversely affected by severe weather events and natural disasters. For example, hurricanes and tropical storms may result in reduced demand for our well completion services in Texas and Louisiana. Adverse weather can also directly impede our own operations. Repercussions of severe weather conditions may include:

• curtailment of services;

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

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

• increase in the price of insurance; and

• loss of productivity.

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

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

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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.

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.

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 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

• 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. We could be exposed to liability for cleanup costs, natural resource damages and other damages under these and other environmental laws. 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. 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.

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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. 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, onboard black box recorder devices or limits on vehicle weight and size.

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

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

New technology may hurt our competitive position.

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

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 (2012 low of $16.05 per share; 2012 high of $23.11 per share), and we expect it to continue to remain volatile given the cyclical nature of our industry.

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The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we were not required to comply with as a private company. Complying with these statutes, regulations and requirements will continue to occupy a significant amount of time of our Board of Directors (the “Board”) and management and will continue to significantly increase our costs and expenses. Following our IPO, we were required to:

• design, establish, document, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

• establish new internal policies, such as those relating to disclosure controls and procedures and insider trading; and

• involve and retain to a greater degree outside counsel and accountants in the above activities.

In addition, as a public company we are subject to these rules and regulations which could require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our Board, particularly to serve on our Audit Committee, and qualified executive officers.

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 22, 2013, we had 54,004,877 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. 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, in connection with our IPO, we opted to be governed by Section 203 of the Delaware General

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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 common stock.

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

Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties

Our corporate headquarters are currently located at 10375 Richmond Avenue, Suite 1910, Houston, Texas 77042. We lease 29,385 square feet of general office space at our corporate headquarters 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 an office park in Houston, Texas that we intend to use as our new corporate headquarters once completed.

As of February 22, 2013, we owned or leased the following additional principal properties:

Location	Type of Facility	Size	Lease or Owned	Expiration of Lease
4460 Hwy 77 Robstown, TX 78380	General office space, warehouse & maintenance center	14.6 acres, 61,000 sq.ft. of building space	Owned	-
5604 Medco Dr. Marshall, TX 75672	General office space, warehouse & maintenance center	14 acres, 37,000 sq.ft. of building space	Land—Leased; Building—Owned	December 18, 2021
6913 N. FM 1788 Midland, TX 79707	Yard	36.25 acres	Owned	-
12031 North Freeway Sayre, OK	General office space, warehouse & maintenance center	20 acres	Land—Leased; Building—Owned	October 16, 2025
1720 N. Airport Weatherford, OK	General office space	9,000 sq. ft. of building space	Lease	October 1, 2014
4946 Hwy 85 Williston, ND	General office space & warehouse	10,000 sq. ft. of building space	Lease	September 30, 2016
4801 Glen Rose Hwy. Granbury, TX 76048	General office space, warehouse & manufacturing and repair facility	17.7 acres, 64,445 sq.ft. of building space	Owned	-
5700 Enterprise Dr. Greenville, TX	General office space, warehouse & inventory management	10 acres, 123,200 sq. ft. of building space	Owned	-

All of the properties listed above, other than the properties located in Greenville, Texas and Granbury, Texas, are utilized by our Stimulation and Well Intervention Services and Wireline Services segments. The listed property in Greenville, Texas is used for centralized company-wide inventory

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management and the listed property in Granbury, Texas is utilized as a manufacturing and service facility for our Equipment Manufacturing segment. We also own or lease several other smaller facilities, and the leases generally have terms of one to three years. We believe that our existing properties are adequate for our operations and their locations allow us to efficiently serve our customers across the United States. We do not believe that any single property is material to our operations and, if necessary, we could readily obtain a replacement facility.

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 other matters involve inherent uncertainty, we believe that the liability, if any, ultimately incurred with respect to such other 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 future 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 Information

On July 29, 2011, our common stock began trading on the NYSE under the symbol “CJES.” On August 3, 2011, we completed our IPO, at which time we issued and sold 4,300,000 shares and selling stockholders sold 8,925,000 shares. The shares were sold at a price to the public of $29.00 per share.

On February 22, 2013, we had 54,004,877 shares of common stock outstanding. The common shares outstanding at February 22, 2013 were held by approximately 13 record holders, excluding stockholders for whom shares are held in “nominee” or “street” name.

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, 2011
Period from July 29, 2011 to September 30, 2011	$	32.94	$	15.60
Quarter ended December 31, 2011		23.32		12.65
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
Period from January 1, 2013 to February 22, 2013		25.35		21.09

On February 22, 2013, the last reported sales price of our common stock on the NYSE was $24.43 per share.

Dividend Policy

We did not pay any cash dividends on our common stock for the periods indicated above. 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.” 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.

Unregistered Sales of Equity Securities

None.

Repurchases of Equity Securities by the Company or Affiliated Purchasers

None.

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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,
	2012		2011		2010		2009			2008
	(In thousands except per share amounts)
Revenue	$	1,111,501	$	758,454	$	244,157	$	67,030		$	62,441
Net income (loss)		182,350		161,979		32,272		(2,430	)		1,121
Net income (loss) per common share
Basic		3.51		3.28		0.70		(0.05	)		0.02
Diluted		3.37		3.19		0.67		(0.05	)		0.02
Total assets		1,012,757		537,849		226,088		150,231			155,212
Long-term debt and capital lease obligations, excluding current portion		173,705		-		44,817		60,668			25,041

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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, which are offered through our Stimulation and Well Intervention Services and Wireline Services segments, are provided in conjunction with both unconventional and conventional well completions as well as stimulation workover operations for existing wells. We seek to differentiate our services from those of our competitors by providing customized solutions for our customers’ most challenging well completions. We believe our customers value the experience, technical expertise, high level of customer service and demonstrated operational efficiencies that we bring to projects. Through our Equipment Manufacturing segment, we manufacture equipment and provide equipment repair services and parts and supplies to fulfill our internal needs and for third party companies in the energy services industry.

We commenced our Wireline Services business with the acquisition of Casedhole Solutions on June 7, 2012. See “Note 4 – Acquisitions” in Item 8 “Financial Statements and Supplementary Data” for further discussion regarding the Casedhole Solutions acquisition. The Casedhole Solutions acquisition provided us with an expanded geographic presence in areas where we previously did not operate, such as the Williston and Uinta basins and the Marcellus, Utica, Avalon and Bone Springs shale formations. We have been successful in leveraging our wireline services to expand our customer base and geographic presence for our other services. We are evaluating additional opportunities with existing and new customers to expand our operations into new areas throughout the United States and internationally.

With the acquisition of Total on April 28, 2011, we commenced our Equipment Manufacturing segment. In addition to manufacturing equipment used in the energy services industry, we also provide equipment repair services and sell oilfield parts and supplies to third-party customers in the energy services industry, as well as to meet our own internal needs. Our company-wide inventory management system is centralized through our Equipment Manufacturing business.

Our Business

Stimulation and Well Intervention Services Segment

Approximately $940.3 million, or 85%, of our consolidated revenues for the year ended December 31, 2012 were derived from our Stimulation and Well Intervention Services segment. Our Stimulation and Well Intervention Services segment provides hydraulic fracturing, coiled tubing and other complementary services, with a focus on complex, technically demanding well completions.

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Hydraulic Fracturing Services. We currently operate eight modern, 15,000 pounds per square inch pressure-rated hydraulic fracturing fleets with an aggregate 274,000 horsepower. We deployed our eighth fleet in January 2013 in the spot market. Our ninth fleet is currently being winterized in preparation for work in the Bakken Shale, and we expect the fleet to be deployed at the end of the first quarter of 2013. The addition of this fleet will increase our total capacity to more than 300,000 horsepower.

Our hydraulic fracturing business contributed $784.9 million, or 71%, of our consolidated revenue and completed 6,243 fracturing stages during the year ended December 31, 2012, compared to $619.8 million of revenue and 3,713 fracturing stages for the previous year. During the year ended December 31, 2012, we averaged monthly revenue per unit of horsepower of $288 compared to $374 for the previous year.

For the year ended December 31, 2012, we derived 55.0% of our consolidated revenues from term contracts. One of our term contracts expired in January 2013, although we have a strong relationship with this customer and negotiated a new agreement for continued work through the first half of 2013 at a pricing discount of approximately 20% from the previous contracted rates. We currently have term contracts in place for three of our hydraulic fracturing fleets, two of which are set to expire in mid-2013 and one of which is set to expire in early 2014. Our term contracts generally range from one year to three years. Under the term contacts, our customers are typically obligated to pay us on a monthly basis for a specified number of hours of service, whether or not those services are actually utilized. To the extent customers use more than the specified contract minimums, we will be paid a pre-agreed amount for the provision of such additional services. Some of our term contracts restrict the ability of the customer to terminate or require our customers to pay us a lump-sum early termination fee, generally representing all or a significant portion of the remaining economic value of the contracts to us.

We charge prevailing market prices per hour for work performed in the spot market and 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. Due to the flexibility of our operating model, our revenue can fluctuate without having a material impact to earnings when our customers elect to source their own proppants. We believe that one of the benefits of working our hydraulic fracturing fleets on a spot market basis is that it serves as a marketing tool, giving us the opportunity to introduce our services to new customers and strengthen our relationships with existing customers.

Coiled Tubing. We currently operate a fleet of 19 coiled tubing units, having deployed one new coiled tubing unit in February 2013, and we have five new coiled tubing units on order that are expected to be delivered and deployed in 2013. Our coiled tubing business contributed $140.2 million, or 14%, of our consolidated revenue and we completed 3,719 coiled tubing jobs during the year ended December 31, 2012, compared to $97.2 million of revenue and 3,183 coiled tubing jobs for the previous year. Our coiled tubing operations also perform other well stimulation services including pumpdown services for wireline and coiled tubing. For the year ended December 31, 2012, we generated $15.2 million of revenue from these services, down from $19.4 million during the year ended December 31, 2011.

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Our coiled tubing and other well stimulation services are generally provided in the spot market at prevailing prices per hour, although we do have two contracts in place with major operators 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.

Wireline Services Segment

Through our Wireline Services segment, which we commenced with the acquisition of Casedhole Solutions on June 7, 2012, we currently operate 64 wireline units and 21 pumpdown units, as well as pressure control equipment. We currently plan to deploy two new wireline units in 2013. Our Wireline Services segment generated $130.1 million, or 11%, of our consolidated revenue from the date of acquisition through December 31, 2012.

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 services 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. We have expertise in both horizontal and high-pressure, high-temperature completion applications and experience in the most complex and demanding operating environments, focusing on oily basins.

Equipment Manufacturing Segment

Our Equipment Manufacturing segment contributed $41.1 million, or 4%, of our consolidated revenue during the year ended December 31, 2012. Our Equipment Manufacturing segment constructs oilfield equipment, including hydraulic fracturing pumps, coiled tubing units, pressure pumping units, wireline units and other equipment, for our Stimulation and Well Intervention Services and Wireline Services segments as well as for third party customers in the energy services industry. This segment also provides equipment repair services and oilfield parts and supplies to the energy services industry and to meet the needs of our Stimulation and Well Intervention Services and Wireline Services segments.

See “Note 11 – Segment Information” in Item 8 “Financial Statements and Supplementary Data” for further discussion regarding the Company’s reportable segments.

General 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 we have taken steps to mitigate them to the extent practicable. In addition, while we believe that we are well positioned to capitalize on available growth opportunities, we may not be able to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read this section in conjunction with the factors described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors” for additional information about the known material risks that we face.

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Trends that we believe are affecting, and will continue to affect, our industry include:

Demand for Our Services.Our business depends on the capital spending programs of our customers. Our Stimulation and Well Intervention Services and Wireline Services segments are significantly driven by the exploration, development and production expenditures made by our customers, which also impacts sales by our Equipment Manufacturing segment to third-party customers in the energy services industry. These customers have historically tended to delay capital equipment projects, including maintenance and upgrades, during industry downturns. 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, including the current and expected future prices for oil and gas, and the perceived stability and sustainability of those prices, as well as production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling and workover budgets.

There is increasing horizontal drilling and completion related activity in oily- and liquids-rich formations due to the significant disparity between oil and natural gas prices on a Btu basis. Further, based on industry data, we believe the price disparity will continue over the near-to-medium term resulting in increasing demand for the types of services that we offer in the unconventional formations with oily- and liquids-rich content. The development of unconventional drilling environments requires more complex, technically demanding completion jobs than conventional drilling activity. Despite this increase in demand, pricing has nonetheless declined in some areas with the migration of drilling and completion capacity from the gassier regions, particularly for hydraulic fracturing where current capacity exceeds demand. We expect this pricing pressure to continue for the near-to-medium term.

We believe that the service-intensive nature of completion activities in unconventional resource formations, in which we have a growing presence, will have a positive long-term impact on demand for our services. Additionally, we believe long-term capital for the continued development of oily formations will be provided in part by the participation of large well-capitalized domestic oil and gas companies that have made significant investments, as well as international oil and gas companies that continue to make significant capital commitments through joint ventures and direct investments in North America’s unconventional resource basins. Although we believe these investments indicate a long-term commitment to development, ultimately oil and natural gas prices and capital expenditures by exploration and production companies, together with any significant future increase in overall market capacity of completion equipment, may affect demand for our services.

Competition.The markets in which we provide our Stimulation and Well Intervention Services and Wireline Services are highly competitive. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies. During 2012, we maintained our presence in oily basins, and have near-term plans to increase our presence in these areas since customer activity levels in natural gas-directed basins has substantially declined due to the low price of natural gas. We expect to continue to benefit from increased horizontal drilling and completion-related activity in those complex unconventional resource formations in oily regions. However, we remain concerned about the migration of drilling activity and completion capacity into the oily- and liquids-rich regions from the gassier regions and the weakness in the price of natural gas and natural gas liquids, as this has continued to increase competition among oilfield service companies in the oily regions and has negatively affected the spot market pricing for our services.

Hydraulic Fracturing Legislation and Regulation. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface

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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. The federal Energy Policy Act of 2005 amended the UIC provisions of the SDWA to exclude hydraulic fracturing from the definition of “underground injection” and thereby exclude the process from direct federal regulation under the SDWA. The hydraulic fracturing process is currently typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving the use of diesel, and has also adopted regulations requiring operators to capture rather than vent most gases that are brought to the surface during well completion activities, beginning in 2015. In addition, legislation has been introduced before Congress to provide for direct federal regulation of hydraulic fracturing and to require public disclosure of chemicals used in the hydraulic fracturing process. Also, many state governments have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, well construction, and operational requirements on hydraulic fracturing operations or otherwise seek to temporarily or permanently ban fracturing activities altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on 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 waste water treatment and disposal. The EPA has indicated that it expects to issue its study report in late 2014. In the interim, however, the EPA has utilized existing statutory authority under the SDWA, the Clean Water Act, CERCLA and the CAA to investigate and pursue actions against some oil and natural gas producers where EPA believes their activities may have impacted air quality or groundwater. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. On April 13, 2012, President Obama issued an executive order creating a task force to coordinate federal oversight over domestic natural gas production and hydraulic fracturing. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various aspects of hydraulic fracturing. These reviews and studies, depending on their results, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory programs. Finally, the U.S. Department of Interior is developing proposed rules that would require oil and natural gas producers to publicly disclose their hydraulic fracturing chemicals in connection with drilling wells on federal and Indian lands and would also strengthen standards for well-bore integrity and the management of fluids that return to the surface during and after fracturing operations on federal and Indian lands.

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting or regulating, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, increase our and our customers’ 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 or regulatory requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

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Results of Operations

Our results of operations are driven primarily by four interrelated variables: (1) drilling and stimulation activities of our customers; (2) the prices we charge for our services; (3) cost of products, materials and labor; and (4) our service performance. We seek to pass the cost of raw materials, such as proppants and chemicals, on to our customers, and historically, our profitability has not been materially impacted by changes in the costs of these materials. To a large extent, the pricing environment for our services will dictate our level of profitability. To mitigate the volatility in utilization and pricing for the services we offer, we currently have active term contracts covering three of our eight existing fleets.

Our revenues and results of operations for the year ended December 31, 2012 have been positively impacted by: (1) the addition and deployment of our fourth hydraulic fracturing fleet in April 2011; (2) the addition and deployment of our fifth hydraulic fracturing fleet in August 2011; (3) the addition and deployment of the vertical portion of our sixth hydraulic fracturing fleet in December 2011 and the horizontal portion in February 2012; (4) the addition and deployment of our seventh hydraulic fracturing fleet in April 2012; (5) the addition and deployment of five new coiled tubing units during 2011; (6) the acquisition of Total in April 2011; and (7) the acquisition of Casedhole Solutions in June 2012, which initiated our Wireline Services segment. 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, 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 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		672,962		425,014		247,948
Selling, general and administrative expenses		108,405		48,360		60,045
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 income (expense):
Interest expense, net		(4,996)		(4,221)		(775)
Loss on early extinguishment of debt		-		(7,605)		7,605
Other income (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

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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 $203.5 million in Stimulation and Well Intervention Services revenue, the Casedhole Solutions acquisition in June 2012 resulting in an additional $130.1 million in Wireline Services revenue and the Total acquisition in April 2011 resulting in $19.1 million in Equipment Manufacturing revenue.

Direct Costs

Direct costs increased $247.9 million, or 58%, to $673.0 million for the year ended December 31, 2012, as compared to $425.0 million the year ended December 31, 2011, primarily due to the significant increase in revenue in 2012. As a percentage of revenue, direct costs increased to 61% for the year ended December 31, 2012 from 56% 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, coupled with a 13% decline in U.S. onshore rig count during 2012.

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

SG&A increased $60.0 million, or 124%, to $108.4 million for the year ended December 31, 2012, as compared to $48.4 million for the year ended December 31, 2011. The increase was primarily due to $21.8 million in SG&A costs related to Casedhole Solutions, $10.6 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 and $3.4 million in incremental SG&A costs related to the acquisition of Total.

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 Casedhole Solutions 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

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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.

Results for the Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010

The following table summarizes the change in our results of operations for the year ended December 31, 2011 when compared to the year ended December 31, 2010 (in thousands):

	Years Ended December 31,
	2011			2010			$ Change
Revenue	$	758,454		$	244,157		$	514,297
Costs and expenses:
Direct Costs		425,014			145,093			279,921
Selling, general and administrative expenses		48,360			16,491			31,869
Depreciation and amortization		22,919			10,711			12,208
(Gain)/Loss on disposal of assets		(25	)		1,571			(1,596	)
Operating income		262,186			70,291			191,895
Other income (expense):
Interest expense, net		(4,221	)		(17,341	)		13,120
Loss on early extinguishment of debt		(7,605	)		-			(7,605	)
Other income (expense), net		(40	)		(309	)		269
Total other expenses, net		(11,866	)		(17,650	)		5,784
Income before income taxes		250,320			52,641			197,679
Provision for income taxes		88,341			20,369			67,972
Net income	$	161,979		$	32,272		$	129,707

Revenue

Revenue increased $514.3 million, or 211%, to $758.5 million for the year ended December 31, 2011, as compared to $244.2 million for the year ended December 31, 2010. This increase was primarily due to the deployment of additional hydraulic fracturing equipment in our Stimulation and Well Intervention Services segment. Fleets 2, 3, 4, 5 and 6A, which were deployed in August 2010, January 2011, April 2011, August 2011 and December 2011, respectively, contributed $351.9 million of incremental revenue in 2011. In addition, we experienced increased utilization of our equipment across all service lines as well as improved pricing for our services. We continued to benefit from increased horizontal drilling and completion-related activity in unconventional resource plays, which enabled us to obtain higher revenues for our hydraulic fracturing services due to the complexity

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of the work performed in these areas. Our Equipment Manufacturing segment, which we added with the acquisition of Total in April 2011, contributed $22.1 million of revenue during 2011.

Direct Costs

Direct costs increased $279.9 million, or 193%, to $425.0 million for the year ended December 31, 2011, as compared to $145.1 million for the year ended December 31, 2010, primarily due to the significant increase in revenue in 2011. In addition, we benefited from economies of scale with the addition of hydraulic fracturing fleets during the year, which is evidenced by a decrease in direct labor costs as a percentage of revenue. Expenses for proppants also decreased as a percentage of revenue due primarily to some of our customers opting to provide their own sand during 2011.

Selling, General and Administrative Expenses (SG&A)

SG&A increased $31.9 million, or 193%, to $48.4 million for the year ended December 31, 2011, as compared to $16.5 million for the year ended December 31, 2010. The increase was primarily due to $10.8 million in higher long-term and short-term incentive costs, $10.3 million in higher payroll and personnel costs associated with the continued hiring of personnel to support our growth, $1.0 million in increased professional fees as a result of the costs associated with being a public company and $2.2 million in higher marketing costs. We also incurred $2.7 million in increased SG&A costs associated with Total in 2011.

Depreciation and Amortization

Depreciation and amortization expenses increased $12.2 million, or 114%, to $22.9 million for the year ended December 31, 2011, as compared to $10.7 million for the year ended December 31, 2010. The increase was primarily related to $9.5 million from the Stimulation and Well Intervention Services segment due to the addition and deployment of new equipment and $2.7 million from the Equipment Manufacturing segment due to the acquisition of Total in April 2011.

Interest Expense

Interest expense decreased by $13.1 million, or 76%, to $4.2 million for the year ended December 31, 2011, as compared to $17.3 million for the year ended December 31, 2010. This decrease was due primarily to charges of $10.4 million incurred in 2010 in connection with the change in fair value of our warrant liability. The warrants were exercised in December 2010. The remaining decrease was primarily attributable to lower average outstanding debt balances and, to a lesser extent, lower interest rates.

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 a new senior secured revolving credit facility. Please read “Description of Our Indebtedness” below for further discussion.

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Income Taxes

We recorded a tax provision of $88.3 million for the year ended December 31, 2011, at an effective rate of 35.3%, compared to a tax provision of $20.4 million for the year ended December 31, 2010, at an effective rate of 38.7%. The 3.4% decrease in our effective rate year over year is primarily attributable to certain qualifying deductions we took in our 2011 federal income tax return that were not taken in previous years. In addition, certain expenses that are non-deductible for income tax purposes decreased during the year relative to pre-tax income.

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, which closed on August 3, 2011. Our primary uses of capital during this period were for the expansion of our operations, including the purchase and maintenance of equipment and the acquisitions of Casedhole Solutions and Total. Our capital expenditures and our maintenance costs have increased substantially over the last few years to support our growth and we expect this trend to continue on a long-term basis as we continue to focus on expanding geographically, both domestically and internationally, while actively evaluating complementary service lines in an effort to further diversify our product offerings. We believe that we are well-positioned to capitalize on available opportunities and finance future growth, although a significant decrease in pricing and utilization for our services may lead to reduced capital expenditures in the near term.

Our Credit Facility (as defined and described in more detail under “Description of Our Indebtedness”) provides for up to $400.0 million of revolving credit, which was increased from $200.0 million in June 2012. As of December 31, 2012, we had $170.0 million outstanding under the Credit Facility, and as of February 22, 2013, we had $155.0 million outstanding along with $0.7 million in letters of credit, leaving $244.3 million available for additional borrowings at that date. Our Credit Facility contains covenants that require us to maintain an interest coverage ratio, to maintain a leverage ratio and to satisfy certain other conditions, as well as 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, 2012, we were, and, as of February 22, 2013, currently are, in compliance with these covenants. For more information concerning the Credit Facility, please read “Description of Our Indebtedness” and “Note 2 – Long Term Debt – Senior Secured Revolving Credit Facility” in Item 8 “Financial Statements and Supplementary Data” for further discussion.

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 expand, upgrade and maintain equipment. Capital expenditures (excluding acquisitions) totaled $182.2 million in

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2012, $169.8 million of which was for growth capital expenditures. In 2013, we plan to spend approximately $75 to $100 million on capital expenditures (excluding acquisitions) for our domestic business based on current equipment orders and current growth estimates, with the upper end of the range reflecting the potential addition of a tenth hydraulic fracturing fleet toward the end of the year. We expect that the majority our 2013 capital expenditures will be spent on new equipment for our Stimulation and Well Intervention Services and Wireline Services segments, as well as on maintenance capital.

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.

We continually monitor new advances in hydraulic fracturing equipment and down-hole technology, as well as new technologies and products that may complement and enhance our existing businesses, and we commit capital funds to upgrade and purchase additional equipment to meet our customers’ needs. Our ninth hydraulic fracturing fleet, which is expected to be deployed late in the first quarter of 2013, has an aggregate cost of approximately $30 million, of which approximately $28.4 million was funded as of February 22, 2013. In addition, we currently have on-order five new coiled tubing units along with related ancillary equipment for delivery and deployment in the first half of 2013, with a combined aggregate cost of approximately $20 million, of which approximately $9.2 million was funded as of February 22, 2013. In an effort to expand our Wireline Services segment, we have also ordered one new wireline unit for delivery and deployment in 2013. This unit has an aggregate cost of approximately $1.4 million, of which $0.3 million was funded as of February 22, 2013. We intend to fund the remaining costs for this equipment through a combination of cash on hand and operating cash flow.

We are actively evaluating opportunities to further enhance and grow our business, including through selective acquisitions and targeted expansion, domestically and internationally. We will continue to make capital investment decisions that we believe will support our long-term growth strategy. The successful execution of our growth strategy depends on our ability to raise capital as needed. 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 of growth in the future. However, we believe we are well positioned to finance our future growth. On June 5, 2012, we increased the borrowing base under our Credit Facility to $400.0 million from $200.0 million. We believe our cash on hand, operating cash flow in excess of our working capital requirements and, if needed, borrowings under our Credit Facility will be sufficient to fund our 2013 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.

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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,
	2012		2011		2010
Cash flow provided by (used in):
Operating activities	$	254,683	$	171,702	$	44,723
Investing activities		(458,146)		(165,545)		(43,818)
Financing activities		171,125		37,806		734
Net change in cash and cash equivalents	$	(32,338)	$	43,963	$	1,639

Cash Provided by Operating Activities

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 Casedhole Solutions. 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 Casedhole Solutions acquisition. 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 as a result of bonus depreciation deductions taken in prior years and the decrease in the rate of bonus depreciation to 50% for 2012 qualifying assets.

Net cash provided by operating activities increased $127.0 million for the year ended December 31, 2011 as compared to the same period in 2010. This increase was primarily due to higher net income and deferred tax expense, partially offset by a reduction in operating cash flows from working capital items. The increase in net income was attributable to the growth in our revenue year over year in connection with the deployment of additional hydraulic fracturing fleets as well as higher utilization and pricing across all of our service lines. Deferred tax expense was higher year over year as a result of the increase in pre-tax income and an increase in temporary differences associated with book versus tax basis of fixed assets. The rate of depreciation on our fixed assets for income tax purposes has increased dramatically since September 2010 as a result of our election to take 100% bonus depreciation on qualifying assets. The reduction in operating cash flows related to working capital items was primarily attributable to increases in accounts receivable, net of increases in various payable items, as a result of the growth of our business.

Cash Flows Used in Investing Activities

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

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acquire Casedhole Solutions as compared to the cash paid to acquire Total, 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 our purchase of Casedhole Solutions. For the year ended December 31, 2011, we spent $27.2 million to acquire Total.

Net cash used in investing activities increased $121.7 million for the year ended December 31, 2011 as compared to the same period in 2010. This increase was due primarily to higher capital expenditures related to the growth of our hydraulic fracturing services business, which tripled in size from two fleets at the end of 2010 to six fleets at the end of 2011. For the year ended December 31, 2011 we spent $100.9 million related to our hydraulic fracturing fleet expansion and $27.2 million related to our acquisition of Total.

Cash Flows Provided by Financing Activities

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. 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 Casedhole Solutions, partially offset by $50.0 million of repayments later in the year.

Net cash provided by financing activities increased $37.1 million for the year ended December 31, 2011 as compared to the same period in 2010. Financing activities for 2011 consisted primarily of $112.1 million in net proceeds from our IPO, the majority of which was used to pay down all of our then-existing debt.

Contractual Obligations

The following table summarizes our contractual cash obligations as of December 31, 2012 (in thousands):

Contractual Obligation	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Credit Facility (1)	$	187,768	$	5,330	$	10,661	$	171,777	$	-
Capital leases (2)		6,055		2,220		3,600		235		-
Operating leases (3)		29,491		10,745		10,787		4,553		3,406
Wireline equipment		1,093		1,093		-		-		-
Vendor supply agreements		30,503		15,219		15,228		31		25
Total	$	254,910	$	34,607	$	40,276	$	176,596	$	3,431

(1) Includes estimated interest expense and related charges at an interest rate of 3.0%.

(2) Capital lease amounts include $0.3 million in interest payments.

(3) On February 21, 2013, we entered into a “build-to-suit” lease agreement with an option to purchase providing for the immediate construction of an office park in Houston, Texas intended to be used as our new corporate headquarters once completed.

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, 2012.

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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 line of credit issuer, Comerica Bank, as line 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 domestic subsidiaries (the “Guarantor Subsidiaries”); non-guarantor subsidiaries are immaterial. Effective June 5, 2012, in connection with the acquisition of Casedhole Solutions, we entered into Amendment No. 1 and Joinder to Credit Agreement (the “Amendment”), among other reasons, to facilitate and permit us to fund a portion of the purchase price of the Casedhole Solutions acquisition.

The Amendment increased our borrowing capacity under the Credit Facility to $400.0 million from $200.0 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 Casedhole Solutions acquisition. As of February 22, 2013, $155.0 million was outstanding under our Credit Facility along with $0.7 million in letters of credit, leaving $244.3 million available for borrowing.

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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 position on all real and personal property of us and the Guarantor Subsidiaries. The weighted average interest rate as of December 31, 2012 was 2.5%.

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 and our subsidiaries’ 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 of up to $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 may be pulled forward from the subsequent fiscal year. These capital expenditure restrictions will 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, 2012, we were, and, as of February 22, 2012, currently are, in compliance with all debt covenants.

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

Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting standards have developed. Accounting standards generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing standards, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable standards on or before their adoption, and we believe the proper implementation and consistent application of the accounting standards are critical.

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the

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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 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 $39.4 million and $19.3 million for the years ended December 31, 2012 and 2011, respectively.

Goodwill, Intangible Assets and Amortization. Goodwill is not amortized, but instead is analyzed on a qualitative basis for indicators of impairment at least annually. To the extent it is determined that the probability of the fair value of the reporting unit exceeding the carrying value of the reporting unit is 50% or lower (“more-likely-than-not” threshold), then we would proceed to the two-step impairment test as defined in the Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”) 350, Intangibles – Goodwill and Other, as amended in September 2011. For the years ended December 31, 2012 and 2011, based on a qualitative analysis, we determined that the fair value of our reporting units more-likely-than-not exceeded their carrying values and therefore, the two-step impairment test was not performed. Prior to 2011, FASB ASC 350 did not allow for a qualitative assessment; rather, the two-step impairment test was required to be performed at least annually. For the year ended December 31, 2010, we performed the two-step impairment test of goodwill, which resulted in the fair value of the reporting unit exceeding the carrying value by more than 2.5 times and therefore concluded that no impairment write-down was necessary.

Similarly, intangible assets with indefinite lives are not amortized, but instead are analyzed on a qualitative basis for indicators of impairment at least annually. In July 2012, the FASB issued Accounting Standards Update (“ASU”) No. 2012-02, Intangibles—Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment. This ASU states that an entity has the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is more likely than not that the indefinite-lived intangible asset is impaired, then the entity is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with Codification Subtopic 350-30, Intangibles — Goodwill and Other — General Intangibles Other than Goodwill.

With the acquisition of Total in April 2011 (see “Note 4 – Acquisitions” in Item 8 “Financial Statements and Supplementary Data”), we recorded two intangible assets, IPR&D and trade name,

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both of which were determined to have indefinite lives. No impairment was recorded for the years ended December 31, 2012 and 2011.

Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized.

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 4 – 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.

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.

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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 enter into arrangements with our customers to provide hydraulic fracturing services, which can be either on a spot market basis or under term contracts. 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 also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate. Under the term contracts, our customers are typically obligated to pay on a monthly basis for a specified number of hours of service, whether or not those services are actually utilized. To the extent customers utilize more than the specified contract minimums, we will be paid a pre-agreed amount for the provision of such additional services.

Coiled Tubing. We enter into arrangements to provide coiled tubing and other well stimulation 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.

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.

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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 $1.1 million at December 31, 2012 and $0.8 million at December 31, 2011. Bad debt expense was $0.6 million, $0.4 million and $0.5 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Stock-Based Compensation. Our stock-based compensation consists of nonqualified stock options and restricted stock. We recognize stock-based compensation expense on a straight-line basis over the requisite service period of the award. We value restricted stock grants based on the closing price of our common stock on the NYSE on the grant date, and we value option grants based on the grant date fair value by using the Black-Scholes option-pricing model, which requires the use of highly subjective assumptions.

The Black-Scholes option-pricing model requires inputs such as the expected term of the grant, expected volatility and risk-free interest rate. Further, the forfeiture rate also affects the amount of aggregate compensation that we are required to record as an expense. We will continue to use judgment in evaluating the expected term, volatility and forfeiture rate related to our stock-based compensation on a prospective basis and will incorporate these factors into our option-pricing model. Each of these inputs is subjective and generally requires significant management judgment. If, in the future, we determine that another method for calculating the fair value of our stock options is more reasonable, or if another method for calculating these input assumptions is prescribed by authoritative guidance, and, therefore, should be used to estimate expected volatility or expected term, the fair value calculated for our employee stock options could change significantly. Higher volatility and longer expected terms generally result in an increase to stock-based compensation expense determined at the date of grant.

Income Taxes.We are subject to income and other similar taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of our annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when we recognize income tax expenses and benefits.

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

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

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

Recent Accounting Pronouncements

In July 2012, the FASB issued ASU No. 2012-02, Intangibles—Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment. This ASU states that an entity has the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with Codification Subtopic 350-30, Intangibles —Goodwill and Other — General Intangibles Other than Goodwill.

Under the guidance in this ASU, an entity also has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period.

The amendments in this ASU are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012 and early adoption is permitted. We elected to early adopt this ASU for the year ended December 31, 2012. The adoption of this update did not have an impact on our consolidated financial statements.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2012, 2011 and 2010. 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, 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 fuel and material purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation services such as proppants, chemicals, guar, coiled tubing and fluid supplies. Our fuel costs consist

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primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials (particularly guar) in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Historically, we have generally been able to pass along price increases to our customers; however, we may be unable to do so in the future. We do not engage in commodity price hedging activities.

Interest Rate Risk. We are exposed to changes in interest rates on our floating rate borrowings under our Credit Facility. The impact of a 1% increase in interest rates on our outstanding debt as of December 31, 2012 and 2010 would have resulted in an increase in interest expense and a corresponding decrease in net income of approximately $1.7 million and $0.7 million, respectively. We had no debt outstanding as of December 31, 2011.

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 of Internal Control Over Financial Reporting	54
Reports of Independent Registered Public Accounting Firm	55
Consolidated Balance Sheets as of December 31, 2012 and 2011	57
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010	58
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December  31, 2012, 2011 and 2010	59
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010	60
Notes to Consolidated Financial Statements	61

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Management’s Report on Internal Control Over Financial Reporting

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

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

Management with the participation of the Company’s principal executive and financial officers assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 using the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework. Management’s assessment included an evaluation of the design of internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Based on this assessment, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2012.

The Company’s internal control over financial reporting as of December 31, 2012 has been audited by UHY LLP, an independent registered public accounting firm, as stated in their report which appears herein.

/s/ Joshua E. Comstock

Joshua E. Comstock, Chairman
and Chief Executive Officer
(Principal Executive Officer)

/s/ Randall C. McMullen, Jr.

Randall C. McMullen, Jr.,
President, Chief Financial Officer
and Treasurer (Principal Financial
Officer)

/s/ Mark C. Cashiola

Mark C. Cashiola, Vice President
and Controller (Principal
Accounting Officer)

February 27, 2013

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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, 2012, and 2011, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012, and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, based on criteria established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ UHY LLP

Houston, Texas

February 27, 2013

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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, 2012, based on criteria established inInternal Control – Integrated Framework 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, 2012, based on criteria established inInternal Control – Integrated Framework 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, 2012, and 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012, and our report dated February 27, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ UHY LLP

Houston, Texas

February 27, 2013

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(AMOUNTSINTHOUSANDS,EXCEPTSHAREDATA)

	As of December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	14,442	$	46,780
Accounts receivable, net		167,481		122,169
Inventories, net		60,659		45,440
Prepaid and other current assets		3,984		9,138
Deferred tax assets		3,613		789
Total current assets		250,179		224,316
Property, plant and equipment, net		433,727		213,697
Other assets:
Goodwill		196,512		65,057
Intangible assets, net		123,487		25,419
Deposits on equipment under construction		1,033		6,235
Deferred financing costs, net		3,848		2,528
Other noncurrent assets		3,971		597
Total assets	$	1,012,757	$	537,849
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	69,617	$	57,564
Payroll and related costs		10,896		4,799
Accrued expenses		17,286		9,626
Income taxes payable		4,029		1,823
Customer advances and deposits		1,092		5,392
Other current liabilities		2,122		33
Total current liabilities		105,042		79,237
Deferred tax liabilities		132,551		62,471
Long-term debt and capital lease obligations		173,705		-
Other long-term liabilities		1,568		1,086
Total liabilities		412,866		142,794
Commitments and contingencies
Stockholders’ equity
Common stock, par value of $0.01, 100,000,000 shares authorized, 53,131,823 issued and outstanding at December 31, 2012 and 51,886,574 issued and outstanding at December 31, 2011		531		519
Additional paid-in capital		224,348		201,874
Retained earnings		375,012		192,662
Total stockholders’ equity		599,891		395,055
Total liabilities and stockholders’ equity	$	1,012,757	$	537,849

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,
	2012		2011		2010
Revenue	$	1,111,501	$	758,454	$	244,157
Costs and expenses:
Direct Costs		672,962		425,014		145,093
Selling, general and administrative expenses		108,405		48,360		16,491
Depreciation and amortization		46,912		22,919		10,711
(Gain) loss on disposal of assets		692		(25)		1,571
Operating income		282,530		262,186		70,291
Other expense:
Interest expense, net		(4,996)		(4,221)		(17,341)
Loss on early extinguishment of debt		-		(7,605)		-
Other expense, net		(105)		(40)		(309)
Total other expense, net		(5,101)		(11,866)		(17,650)
Income before income taxes		277,429		250,320		52,641
Income tax expense		95,079		88,341		20,369
Net income	$	182,350	$	161,979	$	32,272
Net income per common share:
Basic	$	3.51	$	3.28	$	0.70
Diluted	$	3.37	$	3.19	$	0.67
Weighted average common shares outstanding:
Basic		52,008		49,315		46,352
Diluted		54,039		50,780		47,851

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		Amount, at		Paid-in			(Accumulated
	Shares		$0.01 par value		Capital			Deficit)		Total
Balance, December 31, 2009		46,323	$	463	$	66,925		$	(1,589)	$	65,799
Exercise of warrants		1,176		12		10,729			-		10,741
Stock-based compensation		-		-		634			-		634
Net income		-		-		-			32,272		32,272
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

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,
	2012		2011		2010
Cash flows from operating activities:
Net income	$	182,350	$	161,979	$	32,272
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		46,912		22,919		10,711
Deferred income taxes		15,926		45,903		8,327
Provision for doubtful accounts, net of write-offs		600		415		504
(Gain) loss on disposal of assets		692		(25)		1,571
Loss on change in fair value of warrant liability		-		-		10,403
Stock-based compensation expense		18,012		10,846		634
Excess tax benefit from stock-based award activity		(1,916)		(512)		-
Non cash paid in kind interest expense		-		-		278
Amortization of deferred financing costs		923		703		747
Write-off of deferred financing costs related to early extinguishment of debt		-		2,899		-
Changes in operating assets and liabilities:
Accounts receivable		(10,621)		(72,323)		(32,191)
Inventories		(11,263)		(29,201)		(5,719)
Prepaid expenses and other current assets		7,107		(5,416)		(1,708)
Accounts payable		(442)		41,426		2,486
Accrued liabilities		5,373		5,366		6,708
Accrued taxes		3,681		(5,607)		6,254
Deferred income		600		(4,000)		4,000
Other		(3,251)		(3,670)		(554)
Net cash provided by operating activities		254,683		171,702		44,723
Cash flows from investing activities:
Purchases of and deposits on property and equipment		(182,179)		(140,723)		(44,473)
Proceeds from disposal of property and equipment		434		2,400		655
Payments made to acquire Casedhole Holdings, Inc., net of cash acquired		(273,401)		-		-
Payments made to acquire Total E&S, Inc., net of cash acquired		-		(27,222)		-
Investment in unconsolidated subsidiary		(3,000)		-		-
Net cash used in investing activities		(458,146)		(165,545)		(43,818)
Cash flows from financing activities:
Proceeds (payments) on revolving debt, net		170,000		(3,000)		(34,500)
Proceeds from long-term debt		-		12,750		75,888
Repayments of long-term debt		-		(81,789)		(36,920)
Repayments of capital lease obligations		(1,121)		-		(40)
Financing cost payments		(2,243)		(2,939)		(3,696)
Proceeds from exercise of warrants		-		-		2
Proceeds from initial public offering, net of transaction fees		-		112,147		-
Proceeds from stock options exercised		2,573		125		-
Excess tax benefit from stock-based award activity		1,916		512		-
Net cash provided by financing activities		171,125		37,806		734
Net (decrease) increase in cash and cash equivalents		(32,338)		43,963		1,639
Cash and cash equivalents, beginning of year		46,780		2,817		1,178
Cash and cash equivalents, end of year	$	14,442	$	46,780	$	2,817
Supplemental cash flow disclosure:
Cash paid for interest	$	3,975	$	8,417	$	5,796
Cash paid for income taxes	$	75,619	$	46,692	$	5,748

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 related well intervention services through its Stimulation and Well Intervention Services segment to oil and natural gas exploration and production companies in the United States. Subsequent to its June 7, 2012 acquisition of Casedhole Solutions (as defined and described in more detail in “Note 4 – Acquisitions���), the Company provides cased-hole wireline and other complementary services through its Wireline Services segment. In addition, the Company manufactures and repairs equipment and provides oilfield parts and supplies for companies in the energy services industry, as well as fulfills the Company’s internal equipment demands, through its Equipment Manufacturing segment. See “Note 11 – Segment Information” for further discussion regarding the Company’s reportable segments. As used herein, references to the “Company” or “C&J” are to C&J Energy Services, Inc. together with its consolidated subsidiaries.

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 revenues 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, 2012 and 2011, the allowance for doubtful accounts totaled $1.1 million and $0.8 million, respectively. Bad debt expense was $0.6 million, $0.4 million and $0.5 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Inventories. Inventories for the Stimulation and Well Intervention Services segment and the Wireline Services segment consist of finished goods, including equipment components, chemicals,

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NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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

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

	As of December 31,
	2012		2011
Manufacturing parts	$	21,551	$	6,809
Work-in-process		1,523		7,133
Finished goods		38,164		31,844
		61,238		45,786
Inventory reserve		(579)		(346)
	$	60,659	$	45,440

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 $39.4 million, $19.3 million and $9.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. Major classifications of property, plant and equipment and their respective useful lives are as follows (in thousands):

	Estimated   Useful Lives	As of December 31,
		2012		2011
Land	Indefinite	$	1,454	$	1,023
Building and leasehold improvements	5-25 years		26,856		10,996
Office furniture, fixtures and equipment	3-5 years		6,639		2,743
Machinery and equipment	3-10 years		397,747		212,674��
Transportation equipment	5 years		26,048		11,438
			458,744		238,874
Less: accumulated depreciation			(84,848)		(46,539)
			373,896		192,335
Assets not yet placed in service			59,831		21,362
Property, plant and equipment, net		$	433,727	$	213,697

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Goodwill, Intangible Assets and Amortization. Goodwill is not amortized, but instead is analyzed on a qualitative basis for indicators of impairment at least annually. To the extent it is determined that the probability of the fair value of the Company’s reporting unit exceeding the carrying value of the reporting unit is 50% or lower (“more-likely-than-not” threshold), then the Company would proceed to the two-step impairment test as defined in Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”) 350,Intangibles – Goodwill and Other, as amended in September 2011. For the years ended December 31, 2012 and 2011, based on a qualitative analysis, the Company determined that the fair value of its reporting units more-likely-than-not exceeded the carrying value of the reporting unit and therefore, the two-step impairment test was not performed. Prior to 2011, FASB ASC 350 did not allow for a qualitative assessment; rather, the two-step impairment test was required to be performed at least annually. For the years ended December 31, 2010, the Company performed the two-step impairment test of its goodwill and concluded that no impairment write-down was necessary.

Similarly, intangible assets with indefinite lives are not amortized, but instead are analyzed on a qualitative basis for indicators of impairment at least annually. In July 2012, the FASB issued Accounting Standards Update (“ASU”) No. 2012-02, Intangibles—Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment. This ASU states that an entity has the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is more likely than not that the indefinite-lived intangible asset is impaired, then the entity is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with Codification Subtopic 350-30, Intangibles — Goodwill and Other — General Intangibles Other than Goodwill.

With the acquisition of Total in April 2011 (see “Note 4 – Acquisitions”), the Company recorded two intangible assets, IPR&D and trade name, both of which were determined to have indefinite lives. No impairment was recorded for the years ended December 31, 2012 and 2011.

Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized.

Intangible assets consist of the following (in thousands):

	Amortization Period	As of December 31,
		2012		2011
Trade name	10-15 years	$	27,275	$	3,675
Customer relationships	8-15 years		100,193		19,793
Non-compete, backlog and patent	11—48 months		4,601		3,001
IPR&D–Total	Indefinite		854		854
Trade name–Total	Indefinite		6,247		6,247
			139,170		33,570
Less: accumulated amortization			(15,683)		(8,151)
Intangible assets, net		$	123,487	$	25,419

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Total amortization expense for the years ended December 31, 2012, 2011 and 2010 totaled $7.5 million, $3.7 million and $1.1 million, respectively.

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

Years Ending December 31,
2013	$	10,069
2014		9,897
2015		9,245
2016		9,020
2017		8,845
Thereafter		69,310
	$	116,386

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, 2012, 2011 and 2010, no impairment write-down was deemed necessary.

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 accompanying consolidated statements of operations and approximated $0.9 million, $0.7 million and $0.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. Accumulated amortization of deferred financing costs was $1.3 million and $0.4 million at December 31, 2012 and 2011, respectively. Estimated future amortization expense relating to deferred financing costs is as follows (in thousands):

Years Ending December 31,
2013	$	1,160
2014		1,160
2015		1,160
2016		368
	$	3,848

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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

Hydraulic Fracturing Revenue. The Company provides hydraulic fracturing services on either a spot market basis or under term contracts. 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. Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate. Under term contracts, the Company’s customers are typically obligated to pay on a monthly basis for a specified number of hours of service, whether or not those services are actually utilized. To the extent customers use more than the specified contracted minimums, the Company will be paid a pre-agreed amount for the provision of such additional services.

Coiled Tubing. The Company enters into arrangements to provide coiled tubing and other well stimulation services. Jobs for these services are typically short term in nature and 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. The Company typically charges the customer for these services on an hourly basis at agreed upon spot market rates.

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.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Equipment Manufacturing Revenue. The Company enters into arrangements to construct equipment, conduct equipment repair services 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. Through December 31, 2012, only nonqualified stock options and restricted stock have been granted. 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.

Income Taxes. The Company accounts 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.

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, 2012, 2011 and 2010, respectively.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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 unvested 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 stock options and restricted stock.

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

	Years Ended December 31,
	2012		2011		2010
	(In thousands, except per share amounts)
Numerator:
Net income attributed to common shareholders	$	182,350	$	161,979	$	32,272
Denominator:
Weighted average common shares outstanding—basic		52,008		49,315		46,352
Effect of potentially dilutive securities:
Stock options		1,979		1,465		1,499
Restricted stock		52		-		-
Weighted average common shares outstanding—diluted		54,039		50,780		47,851
Earnings per common share:
Basic	$	3.51	$	3.28	$	0.70
Diluted	$	3.37	$	3.19	$	0.67

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,
	2012		2011		2010
	(In thousands)
Basic earnings per share:
Unvested restricted stock		748		-		-
Diluted earnings per share:
Anti-dilutive stock options		1,193		2,344		243
Anti-dilutive restricted stock		30		-		-
Potentially dilutive securities excluded as anti-dilutive		1,223		2,344		243

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Recent Accounting Pronouncements.In July 2012, the FASB issued ASU No. 2012-02, Intangibles — Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment. This ASU states that an entity has the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with Codification Subtopic 350-30, Intangibles — Goodwill and Other — General Intangibles Other than Goodwill.

Under the guidance in this ASU, an entity also has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period.

The amendments in this ASU are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012 and early adoption is permitted. The Company elected to early adopt this ASU for the year ending December 31, 2012. The adoption of this update did not have an impact on the Company’s consolidated financial statements.

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 financial position, results of operations or cash flows of the Company.

Note 2 - Long-Term Debt and Capital Lease Obligations

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

	As of December 31,
	2012		2011
Senior secured revolving credit facility maturing on April 19, 2016	$	170,000	$	-
Capital leases		5,763		-
Total debt and capital lease obligations		175,763		-
Less: amount maturing within one year		(2,058)		-
Long-term debt and capital lease obligations	$	173,705	$	-

Credit Facility

On April 19, 2011, the Company entered into a five-year $200.0 million senior secured revolving credit agreement, as amended (the “Credit Facility”) with Bank of America, N.A., as administrative agent, swing line lender and line of credit issuer, Comerica Bank, as line of credit issuer

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

and syndication agent, Wells Fargo Bank, National Association, as documentation agent, and various other lenders. Obligations under the Credit Facility are guaranteed by the Company’s domestic subsidiaries (the “Guarantor Subsidiaries”); non-guarantor subsidiaries are immaterial. Effective June 5, 2012, in connection with the acquisition of Casedhole Solutions, the Company entered into Amendment No. 1 and Joinder to Credit Agreement (the “Amendment”), among other reasons, to facilitate and permit the Company to fund a portion of the purchase price of the Casedhole Solutions acquisition.

The Amendment increased 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 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, the Company drew $220.0 million from the Credit Facility to fund a portion of the purchase price of the Casedhole Solutions acquisition. As of December 31, 2012, $170.0 million was outstanding under the Credit Facility, leaving $230.0 million available for borrowing.

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 Consolidated Leverage Ratio, which is the 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. All obligations under the Credit Facility are secured, subject to agreed-upon exceptions, by a first priority perfected security position on all real and personal property of the Company and the Guarantor Subsidiaries. The weighted average interest rate as of December 31, 2012 was 2.5%.

The Credit Facility contains customary affirmative 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, 2012.

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

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 - Derivative Liabilities

TheDerivatives and Hedging topic of FASB ASC 815, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts. The guidance provides that an entity should use a two-step approach to evaluate whether an

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

equity-linked financial instrument (or embedded feature) is indexed to its own stock, including evaluating the instrument’s contingent exercise and settlement provisions. The topic also indicates that “contracts issued or held by that reporting entity that are both (1) indexed to its own stock and (2) classified in stockholders’ equity in its statement of financial position” should not be considered derivative instruments.

During 2009, the Company amended and restated the debt agreement associated with an outstanding term loan. In conjunction with this amendment and restatement, the Company executed and delivered a warrant agreement to the lender, whereby the lender (herein referred to as the “Warrant-Holder”) earned warrants over the life of the term loan. Warrants began accumulating in December 2009. The warrants had an exercise price of $0.01 per share and were exercisable upon the settlement of the loan. The term loan was paid in full during 2010. The Warrant-Holder had accumulated 1.2 million warrants as of the date of loan termination and exercised the warrants in full in December 2010.

Prior to the implementation of the derivatives and hedging topic, the warrants, when issued, would have been classified as permanent equity because they met the exception and all of the criteria in the FASB guidance covering accounting for derivative financial instruments indexed to, and potentially settled in, a company’s own stock. However, the agreements covering these warrants contained an embedded conversion feature such that if the Company made certain equity offerings in the future at a price lower than a price specified in the agreements, additional warrants would be issuable to the Warrant-Holder.

The derivatives and hedging topic provides that an instrument’s strike price or the number of shares used to calculate the settlement amount are not fixed if its terms provide for any potential adjustment, regardless of the probability of such adjustment or whether such adjustment is in the entity’s control. If the instrument’s strike price or the number of shares used to calculate the settlement amount are not fixed, the instrument (or embedded feature) is considered to be indexed to an entity’s stock if the only variables that could affect the settlement amount would be inputs to the fair value of a “fixed-for-fixed” forward or option on equity shares.

Under the provisions of the derivatives and hedging topic, the embedded conversion feature in the Company’s warrants were not considered indexed to the Company’s stock because future equity offerings (or sales) of the Company’s stock are not an input to the fair value of a “fixed-for-fixed” option on equity shares.

The final value of the warrants, upon exercise, was determined based on the value of the underlying common stock included in a private offering of the Company’s common stock that occurred during December 2010 ($10.00 per share).

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The effect of these derivative instruments on the consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010 was as follows (in thousands):

			Years Ended December 31,
			2012		2011		2010
Derivative not Designated as Hedging Instruments	Location of Loss Recognized in Operations on Derivative		Amount of Loss Recognized in Operations on Derivative		Amount of Loss Recognized in Operations on Derivative		Amount of Loss Recognized in Operations on Derivative
Equity contracts		Interest expense	$	-	$	-	$	10,403
Total			$	-	$	-	$	10,403

Note 4 - 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. 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 upon their estimated fair values, as follows (in thousands):

Current assets	$	49,619
Property and equipment		73,204
Goodwill		131,455
Other intangible assets		105,600
Other assets		1,459
Total assets acquired	$	361,337
Current liabilities	$	23,081
Capital lease obligations		4,895
Deferred income taxes		52,602
Total liabilites assumed	$	80,578
Net assets acquired	$	280,759

Other intangible assets have a total value of $105.6 million with a weighted average amortization period of approximately 14 years. Other intangible assets consist of customer relationships of $80.4 million, amortizable over 15 years, trade name of $23.6 million, amortizable

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

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

	Years Ended December 31,
	2012		2011
Revenues	$	1,205,864	$	886,721
Net income		194,716		167,842
Net income per common share:
Basic	$	3.74	$	3.40
Diluted		3.60		3.31

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

On April 28, 2011, the Company acquired all of the outstanding common stock of Total E&S, Inc. (“Total”), 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. 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.

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Note 5 – Income Taxes

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

	Years Ended December 31,
	2012		2011		2010
Current provision:
Federal	$	75,205	$	37,687	$	10,502
State		3,948		4,751		1,540
Total current provision		79,153		42,438		12,042
Deferred (benefit) provision:
Federal		16,199		45,039		8,327
State		(273)		864		-
Total deferred (benefit) provision		15,926		45,903		8,327
Provision (benefit) for income taxes	$	95,079	$	88,341	$	20,369

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

	Years Ended December 31,
	2012		2011		2010
Federal statutory rate		35.0%		35.0%		35.0%
State taxes, net of federal benefit		1.4%		1.6%		1.9%
Domestic production activities deduction		-2.6%		-1.5%		0.0%
Other		0.5%		0.2%		1.8%
Effective income tax rate		34.3%		35.3%		38.7%

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

	As of December 31,
	2012		2011
Deferred tax assets:
Accrued liabilities	$	2,877	$	221
Allowance for doubtful accounts		394		289
Other		342		279
Current deferred tax assets		3,613		789
Stock-based compensation		10,370		4,530
Net operating losses		410		-
Other		187		164
Non-current deferred tax assets		10,967		4,694
Total deferred tax assets		14,580		5,483
Valuation allowance		-		-
Total deferred tax assets, net		14,580		5,483
Deferred tax liabilities:
Depreciation on property, plant and equipment		(96,691)		(59,521)
Amortization of goodwill and intangible assets		(45,595)		(7,644)
Other		(1,232)		-
Non-current deferred tax liabilities		(143,518)		(67,165)
Net deferred tax liability	$	(128,938)	$	(61,682)

The Company has approximately $6.5 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 2009 through 2011 remain open to examination under the applicable federal statute of limitations provisions. The Company’s Texas franchise tax returns for the years 2008 through 2011 remain open to examination under the applicable Texas statute of limitations provisions. None of the Company’s federal or state tax returns are currently under examination.

Note 6 – Stock-Based Compensation

On April 5, 2012, the Board of Directors (the “Board”) of the Company approved the C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (the “2012 LTIP”). The 2012 LTIP provides for the grant of stock-based awards to the Company’s officers, employees, consultants and non-employee directors.

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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; and share awards. Only nonqualified stock options and restricted stock have been awarded under the 2012 LTIP as of December 31, 2012. Under the 2012 LTIP, all 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.

The total number of shares of common stock initially available for issuance under the 2012 LTIP is 4.3 million. 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. As of December 31, 2012, there were 3.6 million shares available for issuance under the 2012 LTIP.

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

In connection with the approval of the 2012 LTIP, on May 29, 2012, the 2010 Plan was amended to provide, among other things, that (i) no additional awards would be granted under the 2010 Plan on or after May 29, 2012, (ii) all awards outstanding under the 2010 Plan as of May 29, 2012 would continue to be subject to the terms of the 2010 Plan and the applicable award agreement, and

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(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 each of the periods presented herein.

	Years Ended Decemer 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, 2011 and 2010 was $11.45, $15.30 and $6.64, respectively.

A summary of the Company’s stock option activity for the year ended December 31, 2012 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, 2012		6,797		$	10.94
Granted		134			18.68
Exercised		(465	)		5.53
Forfeited		(200	)		24.64
Outstanding at December 31, 2012		6,266		$	11.06		7.19	$	72,024
Exercisable at December 31, 2012		4,266		$	8.48		6.67	$	57,807

The total intrinsic value of options exercised during the years ended December 31, 2012 and 2011 was $7.0 million and $1.5 million, respectively. No options were exercised prior to 2011. As of December 31, 2012, there was $18.2 million of total unrecognized compensation cost related to outstanding stock options. That cost is expected to be recognized over a weighted-average period of 1.39 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, 2012, 802,000 shares of restricted stock were granted to employees and non-employee directors under the 2012 LTIP at fair market values ranging from $18.01 to $20.89 per share.

A summary of the status and changes during the year ended December 31, 2012 of the Company’s shares of restricted stock is presented below:

	Shares		Weighted-Average Grant-Date Fair Value
	(in thousands)
Non-vested at Jaunary 1, 2012		-	$	-
Granted		802		18.93
Forfeited		(22)		18.89
Vested		(32)		18.89
Non-vested at December 31, 2012		748	$	18.94

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As of December 31, 2012, there was $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 2.4 years. The weighted-average grant-date fair value per share of restricted stock granted during the year ended December 31, 2012 was $18.93. There were no restricted stock grants in 2011 or 2010.

As of December 31, 2012, the Company had 7.0 million stock options and shares of restricted stock outstanding to employees, a consultant 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 $18.0 million, $10.8 million and $0.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. The total income tax benefit recognized in the consolidated statements of operations in connection with stock-based compensation expense was approximately $6.2 million, $3.8 million and $0.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Note 7 – Related Party Transactions

The Company has historically purchased a significant portion of machinery and equipment from Total who, prior to April 28, 2011, was 12% owned by the Company’s chief executive officer. As discussed in Note 4 – Acquisitions, on April 28, 2011 the Company acquired 100% of the outstanding common stock of Total. For the period from January 1, 2011 to April 27, 2011 and for the year ended December 31, 2010, purchases from Total were $26.4 million and $22.2 million, respectively.

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, 2012, 2011 and 2010, purchases from these vendors totaled $2.6 million, $5.7 million and $0.2 million, respectively. Amounts payable to these vendors at December 31, 2012 and 2011 were $0.6 million and $0.8 million, respectively.

The Company purchases certain of its equipment on an arm’s length basis from vendors affiliated with a member of its Board. For the years ended December 31, 2012, 2011 and 2010, purchases from these vendors were $14.7 million, $8.1 million and $0.8 million, respectively. Amounts payable to these vendors at December 31, 2012 and 2011 were $47,000 and $0.7 million, respectively.

The Company obtains office space, equipment rentals, tool repair services and other supplies from vendors affiliated with several employees. For the year ended December 31, 2012, purchases from these vendors were $1.3 million and amounts payable to these vendors at December 31, 2012 were $0.3 million. There were no related party transactions affiliated with any of the Company’s employees for the years ended December 31, 2011 and 2010, respectively.

Note 8 – Business Concentrations

Concentration of Credit Risk

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

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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 81.0%, 92.7% and 90.2% of revenues for the years ended December 31, 2012, 2011 and 2010, respectively. In 2012, sales to Anadarko Petroleum, Apache Corporation and Plains Exploration represented 19.1%, 15.6% and 12.9%, respectively, of the Company’s total sales. In 2011, sales to Anadarko Petroleum, Penn Virginia, EOG Resources, Plains Exploration and EXCO Resources represented 23.1%, 18.2%, 15.9%, 13.2% and 10.4%, respectively, of the Company’s total sales. In 2010, sales to EOG Resources, Penn Virginia, Anadarko Petroleum and Apache accounted for 32.5%, 18.1%, 16.4% and 9.7%, respectively, of the Company’s total sales. 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

Hydraulic Fracturing Term Contracts

The Company has entered into multi-year take-or-pay contracts with certain customers. Under the term contracts, these customers are typically obligated to pay on a monthly basis for a specified number of hours of service, whether or not those services are actually utilized. To the extent customers use more than the specified contract minimums, the Company will be paid for the provision of such additional services based on rates stipulated in the contract. The revenue related to these contracts is recognized on the earlier of the passage of time under terms set forth in each contract or as the services are performed. The contracts expire at various dates through 2014.

Environmental

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

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

Litigation

The Company is, and from time to time may be, involved in claims and litigation arising in the ordinary course of business. Because there are inherent uncertainties in the ultimate outcome of such

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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 and in selling, general and administrative expenses on the consolidated statement of operations.

Supplier Agreements

The Company has non-cancelable purchase agreements with suppliers of goods and services. The terms of these contracts range from one to seven years and have various minimum purchase requirements. As of December 31, 2012, the minimum purchase obligations under these supplier agreements were $15.2 million, $15.2 million and $15,600 for 2013, 2014, and 2015, respectively.

Operating Leases

The Company leases certain property and equipment under non-cancelable operating leases. The term of the operating leases generally range from 12 to 60 months.

Lease expense under all operating leases totaled $12.3 million, $5.5 million and $2.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. As of December 31, 2012, the future minimum lease payments under non-cancelable operating leases were as follows (in thousands):

Years Ending December 31,
2013	$	10,745
2014		6,912
2015		3,874
2016		2,920
2017		1,633
Thereafter		3,406
	$	29,490

On February 21, 2013, the Company entered into a “build-to-suit” lease agreement with an option to purchase providing for the immediate construction of an office park in Houston, Texas intended to be used as the Company’s new corporate headquarters once complete.

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Note 10 – Employee Benefit Plans

The Company maintains two contributory profit sharing plans under a 401(k) arrangement which covers all employees meeting certain eligibility requirements. Eligible employees can make annual contributions to the plans up to the maximum amount allowed by current federal regulations. The Company matches dollar for dollar all contributions made by eligible employees up to 4% of their gross salary. The Company’s 401(k) contributions for the years ended December 31, 2012, 2011 and 2010 totaled $1.0 million, $0.3 million and $0.2 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 related well intervention services, with a focus on complex, technically demanding well completions.

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 the Company’s Stimulation and Well Intervention Services and Wireline Services segments, as well as for third-party customers in the energy services industry.

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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. Financial information for the year ended December 31, 2010 has not been presented because the Company did not have separate operating segments prior to the acquisition of Total in April 2011.

	Stimulation & Well Intervention Services		Wireline Services		Equipment Manufacturing		Corporate and Other			Total
	(in thousands)
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, 2012, 2011 and 2010 was as follows (in thousands):

	Years Ended December 31,
Service Line	2012		2011		2010
Hydraulic fracturing	$	784,923	$	619,772	$	182,657
Coiled tubing		155,335		116,619		61,500
Total revenue	$	940,258	$	736,391	$	244,157

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, acquisition costs, and non-routine items including loss on early extinguishment of debt and legal settlement charges (“Adjusted EBITDA”), because Adjusted EBITDA is considered an important measure of each segment’s performance. In addition, management believes that the disclosure of

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Adjusted EBITDA as a measure of each segment’s operating performance allows investors to make a direct comparison to competitors, without regard to differences in capital and financing structure. Investors should be aware, however, that there are limitations inherent in using Adjusted EBITDA as a measure of overall profitability because it excludes significant expense items. An improving trend in Adjusted EBITDA may not be indicative of an improvement in the Company’s profitability. To compensate for the limitations in utilizing Adjusted EBITDA as an operating measure, management also uses U.S. GAAP measures of performance, including operating income and net income, to evaluate performance, but only with respect to the Company as a whole and not on a segment basis.

As required under Regulation G 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,
	2012		2011
Adjusted EBITDA	$	336,712	$	285,388
Interest expense, net		(4,996)		(4,221)
Loss on early extinguishment of debt		-		(7,605)
Provision for income taxes		(95,079)		(88,341)
Depreciation and amortization		(46,912)		(22,919)
Gain (loss) on disposal of assets		(692)		25
Costs to acquire Total		-		(348)
Costs to acquire Casedhole		(833)		-
Legal settlement		(5,850)		-
Net income	$	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, 2012 and 2011 are presented below (in thousands, except per share amounts).

	Quarters Ended
	March 2012		June 2012		September 2012		December 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

	Quarters Ended
	March 2011		June 2011		September 2011		December 2011
Revenue	$	127,205	$	182,171	$	229,027	$	220,051
Operating income		48,421		60,383		74,452		78,930
Income before income taxes		46,451		51,551		73,785		78,533
Net income		29,085		33,238		46,274		53,382
Net income per common share
-Basic	$	0.61	$	0.70	$	0.92	$	1.03
-Diluted	$	0.60	$	0.68	$	0.89	$	1.00

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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, 2012.

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, 2012, 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 at December 31, 2012. 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 54 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 at December 31, 2012. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2012, is included on page 56 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, 2012 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 2013 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, 2012.

Item 11. Executive Compensation

The information required by this item is incorporated by reference to our definitive proxy statement for our 2013 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, 2012.

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, 2012.

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)	6,265,436	$11.06	3,592,405
Equity compensation plans not approved by security holders	-	-	-
Total	6,265,436	$11.06	3,592,405

⁽¹⁾  Consists of (i) 1,567,118 non-qualified stock options issued and outstanding under the C&J Energy Services, Inc. 2006 Stock Option Plan (the “2006 Plan”), (ii) 4,620,888 non-qualified stock options issued and outstanding under the C&J Energy Services, Inc. 2010 Stock Option Plan (the “2010 Plan”) and (iii) 77,430 non-qualified stock options issued and outstanding under the C&J Energy Services, Inc. Long-Term Incentive Plan (the “2012 LTIP”). There were also 748,398 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 7—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 2013 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, 2012.

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 2013 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, 2012.

Item 14. Principal Accounting Fees and Services

The information required by this item is incorporated by reference to our definitive proxy statement for our 2013 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, 2012.

Item 15. Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

Our Consolidated Financial Statements and accompanying footnotes are included under Part II, Item 8 “Financial Statements and Supplementary Data” of this Form 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))
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))

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Exhibit No.	Description of Exhibit.
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 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))

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Exhibit No.	Description of Exhibit.
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))
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+	Amendment to the C&J Energy Services, Inc. 2006 Stock Option Plan, dated May 29, 2012 (incorporated herein by reference to Exhibit 10.3 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 1, 2012 (File No. 001-35255))
10.3+	Amendment to the C&J Energy Services, Inc. 2010 Stock Option Plan, dated May 29, 2012 (incorporated herein by reference to Exhibit 10.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 1, 2012 (File No. 001-35255))
10.4	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)
10.5	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))
10.6	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))
10.7+	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))

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Exhibit No.	Description of Exhibit.
10.8+	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))
10.9+	Amended and Restated Employment Agreement effective December 23, 2010 between C&J Energy Services, Inc. and Bretton W. Barrier (incorporated herein by reference to Exhibit 10.9 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))
10.10+	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))
10.11+	Executive Employment Agreement effective as of March 24, 2010 by and between Casedhole Holdings, Inc. and Donald J. Gawick (incorporated by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K filed on October 31, 2012 (File No. 001-35255))
10.12+	First Amendment to Executive Employment Agreement effective as of December 27, 2010 by and between Casedhole Holdings, Inc. and Donald J. Gawick (incorporated by reference to Exhibit 10.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K filed on October 31, 2012 (File No. 001-35255))
10.13+	Separation and Release Agreement effective as of October 29, 2012 by and between C&J Energy Services, Inc. and Mr. Bretton W. Barrier (incorporated by reference to Exhibit 10.3 to C&J Energy Services, Inc.’s Current Report on Form 8-K filed on October 31, 2012 (File No. 001-35255))
10.14	Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated as of December 23, 2010 (incorporated herein by reference to Exhibit 10.15 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
10.15	First Amendment to the Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated as of May 12, 2011 (incorporated herein by reference to Exhibit 10.16 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))
10.16	Second Amendment to Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated July 14, 2011 (incorporated herein by reference to Exhibit 10.19 to C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated July 18, 2011 (Registration No. 333-173177))
10.17	Registration Rights Agreement, dated December 23, 2010, among C&J Energy Services, Inc., certain of our stockholders and FBR Capital Markets & Co. (incorporated herein by reference to Exhibit 10.17 to C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))

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Exhibit No.	Description of Exhibit.
*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

* 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 27^th day of February, 2013.

C&J Energy Services, Inc.
By:	/s/ Randall C. McMullen, Jr.
	Randall C. McMullen, Jr.
	President, Chief Financial Officer and Treasurer (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 27, 2013
	Joshua E. Comstock, Chairman and Chief Executive Officer (Principal Executive Officer)
By:	/s/ Randall C. McMullen, Jr.	February 27, 2013
	Randall C. McMullen, Jr., President, Chief Financial Officer and Treasurer (Principal Financial Officer)
By:	/s/ Mark C. Cashiola	February 27, 2013
	Mark C. Cashiola, Vice President and Controller (Principal Accounting Officer)
By:	/s/ James P. Benson	February 27, 2013
	James P. Benson, Director
By:	/s/ Darren M. Friedman	February 27, 2013
	Darren M. Friedman, Director
By:	/s/ Michael Roemer	February 27, 2013
	Michael Roemer, Director
By:	/s/ C. James Stewart III	February 27, 2013
	C. James Stewart III, Director
By:	/s/ H. H. “Tripp” Wommack, III	February 27, 2013
	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))
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 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))

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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))
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+	Amendment to the C&J Energy Services, Inc. 2006 Stock Option Plan, dated May 29, 2012 (incorporated herein by reference to Exhibit 10.3 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 1, 2012 (File No. 001-35255))
10.3+	Amendment to the C&J Energy Services, Inc. 2010 Stock Option Plan, dated May 29, 2012 (incorporated herein by reference to Exhibit 10.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on June 1, 2012 (File No. 001-35255))
10.4	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)
10.5	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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10.6	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))
10.7+	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))
10.8+	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))
10.9+	Amended and Restated Employment Agreement effective December 23, 2010 between C&J Energy Services, Inc. and Bretton W. Barrier (incorporated herein by reference to Exhibit 10.9 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))
10.10+	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))
10.11+	Executive Employment Agreement effective as of March 24, 2010 by and between Casedhole Holdings, Inc. and Donald J. Gawick (incorporated by reference to Exhibit 10.1 to C&J Energy Services, Inc.’s Current Report on Form 8-K filed on October 31, 2012 (File No. 001-35255))
10.12+	First Amendment to Executive Employment Agreement effective as of December 27, 2010 by and between Casedhole Holdings, Inc. and Donald J. Gawick (incorporated by reference to Exhibit 10.2 to C&J Energy Services, Inc.’s Current Report on Form 8-K filed on October 31, 2012 (File No. 001-35255))
10.13+	Separation and Release Agreement effective as of October 29, 2012 by and between C&J Energy Services, Inc. and Mr. Bretton W. Barrier (incorporated by reference to Exhibit 10.3 to C&J Energy Services, Inc.’s Current Report on Form 8-K filed on October 31, 2012 (File No. 001-35255))
10.14	Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated as of December 23, 2010 (incorporated herein by reference to Exhibit 10.15 to C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
10.15	First Amendment to the Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated as of May 12, 2011 (incorporated herein by reference to Exhibit 10.16 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))

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10.16	Second Amendment to Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated July 14, 2011 (incorporated herein by reference to Exhibit 10.19 to C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated July 18, 2011 (Registration No. 333-173177))
10.17	Registration Rights Agreement, dated December 23, 2010, among C&J Energy Services, Inc., certain of our stockholders and FBR Capital Markets & Co. (incorporated herein by reference to Exhibit 10.17 to C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
*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

* 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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