C&J Energy Services 10-K 2011 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, 2011.

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	20-5673219
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
10375 Richmond Avenue, Suite 2000 Houston, Texas	77042
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 260-9900

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

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

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

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

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

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

Large accelerated filer ¨ Accelerated filer ¨      Non-accelerated filer x    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

On July 29, 2011 the registrant’s common stock began trading on the New York Stock Exchange under the symbol “CJES”. Accordingly, as of June 30, 2011 (the date of the registrant’s most recently completed second fiscal quarter), the registrant’s common stock was not listed on an exchange and, therefore, the aggregate market value of the registrant’s common stock held by non-affiliates on such date cannot be reasonably determined.

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at February 24, 2012, was 51,889,242.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		5
Item 1A.	Risk Factors		19
Item 1B.	Unresolved Staff Comments		30
Item 2.	Properties		31
Item 3.	Legal Proceedings		32
Item 4.	Mine Safety Disclosures		32
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		33
Item 6.	Selected Financial Data		34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		54
Item 8.	Financial Statements and Supplementary Data		55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		82
Item 9A.	Controls and Procedures		82
Item 9B.	Other Information		83
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		84
Item 11.	Executive Compensation		96
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		113
Item 13.	Certain Relationships and Related Transactions, and Director Independence		115
Item 14.	Principal Accounting Fees and Services		119
PART IV
Item 15.	Exhibits and Financial Statement Schedules		120
	Signatures		124

-i-

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 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, 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;

• delay in or failure of delivery of our new fracturing fleets or future orders of specialized equipment;

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

• overcapacity and competition in our industry;

-3-

• 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 and other difficulties in executing our long-term growth strategy;

• 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.

-4-

PART I

Item 1. Business

Our History and Structure

We were formed in 1997 as a partnership pursuant to the laws of the State of Texas and reorganized as a Texas corporation in 2006. In connection with our initial public offering (“IPO”), we converted to a Delaware corporation on December 15, 2010. On July 28, 2011, our registration statement on Form S-1 (File No. 333-173177) relating to our IPO was declared effective by the SEC and on July 29, 2011 we began trading on the New York Stock Exchange (“NYSE”) under the symbol “CJES.”

C&J Energy Services, Inc. (“C&J”) is a holding company and substantially all of its operations are conducted through, and substantially all of its assets are held by C&J Spec-Rent Services, Inc., an Indiana corporation (“Spec-Rent”), and Total E&S, Inc., an Indiana corporation (“Total”). C&J owns 100% of the outstanding capital stock of Spec-Rent and in April 2011 Spec-Rent acquired 100% of the outstanding capital stock of Total, a manufacturer of hydraulic fracturing, coiled tubing, pressure pumping and other equipment used in the energy services industry and one of our largest suppliers of machinery and equipment. C&J, Spec-Rent and Total are herein collectively referred to as the “Company,” or “we,” “us,” or “our” and Spec-Rent and Total are herein collectively referred to as the “Subsidiaries.”

Our principal executive offices are located at 10375 Richmond Avenue, Suite 2000, 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 (the “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, 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 or any other report that we may file with or furnish to the SEC.

Our Business

We are an independent provider of premium hydraulic fracturing, coiled tubing and pressure pumping services with a focus on complex, technically demanding well completions. These services, which are offered through our Stimulation and Well Intervention Services segment, are provided in conjunction with both unconventional and conventional well completions as well as stimulation and workover operations for existing wells. In addition, our Equipment Manufacturing segment, which is conducted through Total, manufactures and repairs equipment for our internal needs as well as for third-party companies in the energy services industry.

We provide our Stimulation and Well Intervention Services in what we believe to be some of the most geologically challenging basins in South Texas, East Texas/North Louisiana, Western Oklahoma and West Texas/East New Mexico. We currently operate six modern, 15,000 pounds per square inch, pressure rated hydraulic fracturing fleets with an aggregate 210,000 horsepower, and we currently have on order three additional hydraulic fracturing fleets, which, upon delivery, will increase our total capacity to more than 300,000 horsepower by the end of 2012. Our hydraulic fracturing

-5-

equipment is specially designed to handle well completions with long lateral segments and multiple fracturing stages in high-pressure formations.

We also operate a fleet of 18 coiled tubing units and we have six new coiled tubing units on order, which we expect to be delivered and deployed by the end of 2012. Additionally, we have 21 double pumps and nine single pumps in our standalone pressure pumping line. In anticipation of the delivery and deployment of this new equipment in 2012, we are evaluating opportunities with existing and new customers to expand our operations into new areas throughout the United States with similarly demanding completion and stimulation requirements.

With the acquisition of Total on April 28, 2011, we commenced our Equipment Manufacturing business. In addition to manufacturing hydraulic fracturing, coiled tubing, pressure pumping and other equipment used in the energy services industry, through Total 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. Following our acquisition of Total, we acquired approximately ten acres of property adjacent to Total’s current facility and constructed an approximate 36,000 square foot manufacturing facility, which was completed in December 2011. By significantly increasing Total’s manufacturing capacity, we expect to further increase its ability to service our Stimulation and Well Intervention Services segment and existing and future third-party customers, and to enhance our research and development efforts around equipment and innovation.

Our Operating Segments

Prior to the acquisition of Total in April 2011, we had one operating segment with three related service lines: hydraulic fracturing, coiled tubing and pressure pumping. During the second quarter of 2011, we reevaluated our business and concluded that, with the acquisition of Total, two operating and reportable segments exist: (1) Stimulation and Well Intervention Services and (2) Equipment Manufacturing, each of which is 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” to our consolidated financial statements.

Stimulation and Well Intervention Services

Hydraulic Fracturing. Our customers utilize 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 crack, 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 cracks (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. The aggregate volume of hydraulic fracturing fluid (not including proppants or other additional substances) used in our hydraulic fracturing services to our customers varies

-6-

significantly among each well completion or workover depending on the number of fracturing stages requested by our customers. During the year ended December 31, 2011, we performed individual well completions ranging from a minimum of one fracturing stage to a maximum of 33 fracturing stages, with the average well completion consisting of 11 fracturing stages. Our hydraulic fracturing business contributed $619.8 million to our revenue for the year ended December 31, 2011 and completed 3,713 fracturing stages during the year ended December 31, 2011.

Coiled Tubing. Our customers utilize our coiled tubing services to perform various functions associated with well-servicing operations and to facilitate completion of horizontal wells. Coiled tubing services involve the insertion of steel tubing into a well to convey materials and equipment to perform various applications on either a completion or workover assignment. We believe coiled tubing has become a preferred method of well completion, workover and maintenance projects due to the 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. We have successfully leveraged our existing relationships with coiled tubing customers to expand our fracturing business. Our coiled tubing operations contributed $97.2 million to our revenue for the year ended December 31, 2011 and we completed 3,183 coiled tubing jobs during the year ended December 31, 2011.

Pressure Pumping. Our customers utilize our stand-alone pressure pumping services primarily in connection with completing new wells and remedial and production enhancement work on existing wells. Our pressure pumping services include well injection, cased-hole testing, workover pumping, mud displacement, wireline pumpdowns and pumping-down coiled tubing. Our pressure pumping services often provide us with advance knowledge of a customer’s need for coiled tubing services, and are often used in conjunction with our coiled tubing services. Our pressure pumping business generated $19.4 million of revenue for the year ended December 31, 2011.

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 segment as well as for third-party customers in the energy services industry. This business segment also provides equipment repair services and oilfield parts and supplies to the energy services industry, as well as to meet our own internal needs. Our Equipment Manufacturing segment, which we added with the acquisition of Total in April 2011, contributed $22.1 million in third-party revenue for the year ended December 31, 2011.

Our Industry

Our business depends on the capital spending programs of our customers. Our Stimulation and Well Intervention Services are significantly driven by the exploration, development and production expenditures made by our customers, which also impacts sales by our Equipment Manufacturing business to third-party customers in the energy services industry, who 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.

-7-

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 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 hydraulic fracturing equipment, may affect demand for our services.

Increased Horizontal Drilling and Greater Service Intensity in Unconventional Basins. We believe exploration and production companies have shown a preference for a customized approach to completing complex wells in unconventional basins. Even if overall market capacity of hydraulic fracturing equipment increases, we believe the required attention and experience to complete the most difficult fracturing jobs in these service-intensive basins will continue to increase. 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 1,165 as of February 24, 2012, and as of such date represented 58.8% 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 are 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 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 services in oily- and liquids-rich basins. We expect to continue to benefit from increased horizontal drilling and completion-related activity in those complex unconventional resource plays that are oily- and liquids-rich, even as those areas absorb drilling and completion capacity moving from the gassier regions.

-8-

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 horizons and improve overall field economics. We believe that there are thousands of 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.

High Levels of Asset Utilization and Increased Attrition Should Positively Impact our Equipment Manufacturing Business. Existing hydraulic fracturing fleets are currently experiencing high levels of utilization as the result of a significant increase in the number of fracturing stages per horizontal well and increased pump pressure rates associated with the fracturing stages, which are designed to maximize shale oil and gas production. Additionally, advances such as pad drilling and zipper-fracs, whereby an operator drills two offset wells for simultaneous completion, have led to more wells being drilled per rig and, thus, have increased levels of asset utilization in the hydraulic fracturing industry. The higher level of operation is expected to accelerate the replacement cycle of equipment and result in increased attrition of existing hydraulic fracturing equipment.

Financial Information About Geographic Areas

During the three year period ended December 31, 2011, 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.

Seasonality

Our results of operations have not historically reflected any material seasonal tendencies and we currently do not believe that seasonal fluctuations will have a material impact on either our Stimulation and Well Intervention Services or Equipment Manufacturing businesses in the foreseeable future.

Sales and Marketing

Our sales and marketing activities relating to our Stimulation and Well Intervention 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.

We have traditionally used our coiled tubing and pressure pumping services to expand our customer base and enter new markets, which in turn provides additional opportunities for our fracturing services. In many cases, our initial successful work with our customers in one particular

-9-

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 leverage our existing customer base, as well as establish new relationships with additional operators, to selectively expand our hydraulic fracturing, coiled tubing and pressure pumping services to other basins that have similar characteristics to those in which we currently operate.

With respect to our Equipment Manufacturing business, we sell and market to oilfield services companies throughout the United States. During the fourth quarter of 2011, we completed the construction of a 36,000 square foot manufacturing facility adjacent to Total’s existing facility. This expansion positions Total to expand its customer base and meet a growing backlog of third-party orders. The expansion also enhances our research and development efforts around equipment and innovation and should also allow Total to continue to streamline our manufacturing capabilities and further lower our equipment costs, while shortening delivery times.

Customers

The majority of our revenues are generated from our fracturing services. Our customers served are primarily independent oil and natural gas exploration and production companies. 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 our 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 our total sales. In 2009, sales to Penn Virginia, Anadarko Petroleum and EnCana represented 25.9%, 11.7% and 11.0%, respectively, of our total sales. Our top ten customers in our Stimulation and Well Intervention Services segment accounted for approximately 92.7 %, 90.2% and 90.6% of our consolidated revenues for the years ended December 31, 2011, 2010 and 2009, respectively. We currently own six fracturing fleets and have ordered three additional fracturing fleets, which are expected to be delivered during 2012. 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 continued efforts to increase the number of fracturing fleets we operate will allow us to serve a larger number of customers and reduce customer concentration.

The customers served through our Equipment Manufacturing business are primarily oilfield services companies. As noted elsewhere in this Form 10-K, 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 pressure pumps and is currently constructing the fracturing pumps on our three on-order fleets. Total has also constructed all of our coiled tubing and pressure pumping equipment since 2004. Our Equipment Manufacturing business did not generate a significant portion of our consolidated revenues for the year ended December 31, 2011.

Competition

The markets in which we provide our Stimulation and Well Intervention Services are highly competitive. We provide our services and products across South Texas, East Texas/North Louisiana, Western Oklahoma and West Texas/New Mexico, 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

-10-

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. The development of unconventional oil and gas resources is driving the need for complex, new technologies, completion techniques and equipment to help increase recovery rates, lower production costs and accelerate field development. 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.

In our Equipment Manufacturing Business 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 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, such as fracturing sand, fracturing chemicals, coiled tubing and fluid 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, 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. 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. During the year ended December 31, 2010, we purchased 5% or more of our materials or equipment from each of Economy Polymers & Chemicals, Total, Weir SPM and Sintex Minerals & Services, Inc.

With respect to our Equipment Manufacturing business, in 2011 approximately 92.3% of our costs of goods sold consisted of raw materials and component parts, with the other 7.7% 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, 2011, two of our vendors, Holt Caterpillar and Weir SPM, accounted for more than 10% of our raw materials and component parts purchases.

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

-11-

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 segment are subject to hazards inherent in the oil and gas industry, including accidents, blowouts, explosions, craterings, fires, oil spills and hazardous materials spills. These conditions can cause:

• personal injury or loss of life;

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

• suspension of operations.

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

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 comprehensive general liability insurance coverage of types and amounts that we believe to be customary in the industry, including sudden & accidental pollution insurance. Our sudden and accidental pollution insurance coverage currently consists of $1.0 million each occurrence underlying coverage, with $25.0 million each occurrence umbrella coverage and an additional $25.0 million each occurrence excess coverage. As discussed below, our Master Service Agreements 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.

-12-

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

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

The description of insurance policies set forth above is a summary of the material terms of our insurance policies currently in effect and may change in the future as a result of market and/or other conditions. Similarly, the summary of MSAs set forth above is a summary of the material terms of the typical MSA that we have in place and does not necessarily reflect every MSA that we have entered into or may enter into in the future.

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.

-13-

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 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 consolidated financial statements. 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 “Sperfund 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

-14-

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 production operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging of disposal wells or 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 production 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 Federal Water Pollution Control 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 Federal Water Pollution Control 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.

-15-

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. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation 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 drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 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 regulate hydraulic fracturing under the SDWA or otherwise. Legislation has been introduced before Congress from time to time, including in the current session, 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

-16-

fracturing services that we render for our exploration and production customers. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business.

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

We maintain insurance against some risks associated with underground contamination that may occur as a result of well services activities. However, this insurance is limited to activities at the 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 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.

On July 28, 2011, the EPA issued proposed rules that would 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 EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include 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 proposed 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. Final action on the proposed rules is expected no later than April 3, 2012.

-17-

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. On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”), present an endangerment to public health and welfare 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 GHGs from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG sources, including, among others, certain oil and natural gas production facilities, on an annual basis. We do not believe our operations are currently subject to these requirements, but our business could be affected if our customers’ operations become subject to these or other similar requirements. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and gas our customers produce, and thus have a material adverse effect on the demand for our products and services.

In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. 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 24, 2012, we had 1,127 employees, 223 of whom were full-time salaried personnel. Most of our remaining employees are hourly personnel. We will hire additional employees as we expand our hydraulic fracturing fleets and undertake other large projects and, 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.

-18-

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 the documents and other information incorporated by reference herein. The risks and uncertainties described herein and therein are not the only ones we face. If any of these risks were to actually occur, our business, financial condition and results of operations could be harmed and we may not be able to achieve our goals. Additional risk factors not presently known to us or which we currently consider immaterial may also adversely affect us.

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, 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;

-19-

• 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. In 2009, our industry experienced an unprecedented decline in drilling activity in the United States as rig counts dropped by approximately 57% from 2008 highs. Correlating with this decline, the Henry Hub spot price for natural gas decreased from an average of $8.90 per mcf in 2008 to $4.16 per mcf in 2009. Prices for natural gas rebounded somewhat in 2010, although the average was only $4.38 per mcf. The Cushing WTI Spot Oil Price averaged $99.67, $61.65 and $79.39 per barrel in 2008, 2009 and 2010, respectively. Natural gas prices did not exceed $4.92 per mcf in 2011 and averaged $4.00 per mcf during that year, while oil prices averaged $94.88 per barrel during that time. As of February 24, 2012, the Henry Hub spot price for natural gas was $2.59 per mcf and the Cushing WTI Spot Oil Price was $109.49 per barrel. Unexpected material declines in oil and natural gas prices, or drilling or completion activity in the southern United States 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.

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.

Currently, the demand for hydraulic fracturing services and coiled tubing services exceeds the availability of equipment and crews across the industry generally and in our operating areas in particular. As a result, we and our competitors have ordered additional fracturing equipment to meet existing and projected long-term demand. We currently have three hydraulic fracturing fleets and six coiled tubing spreads on order and expected for delivery in 2012. Significant increases in overall market capacity could cause our competitors to lower their rates and could lead to a decrease in rates in the oilfield services industry generally. Additionally, the recent declines in natural gas prices has resulted in reduced drilling activity in natural gas shale plays, which has driven oilfield services companies operating in natural gas shale plays to relocate their equipment to more oily- and liquids-rich shale plays, such as the Eagle Ford Shale and Permian Basin. As the number of crews in the these area increases, the increase in supply relative to demand may result in lower prices and utilization of our services and could adversely affect our business and results of operations.

-20-

Our inability to acquire or delays in the delivery of our new fracturing fleets or future orders of specialized equipment from suppliers could harm our business, results of operations and financial condition.

We currently have three new hydraulic fracturing fleets on order, Fleets 7, 8 and 9. We expect to take delivery of Fleet 7 in April 2012, Fleet 8 in the third quarter of 2012 and Fleet 9 in the fourth quarter of 2012. The delivery of Fleets 7, 8 and 9, or any other fracturing fleets we may order in the future, could be materially delayed or not delivered at all. The overall number of hydraulic fracturing equipment suppliers in the industry is limited, and there is high demand for such equipment, which may increase the risk of delay or failure to deliver and limit our ability to find alternative suppliers. Any material delay or failure to deliver new fleets could defer or substantially reduce our revenue from the deployment of these fracturing fleets.

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 pressure pumping 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 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. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation 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 drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 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

-21-

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 regulate hydraulic fracturing under the SDWA or otherwise. 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 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 Chief Executive Officer, President and Chairman. If we lose the services of Mr. Comstock, our other executive officers or other key personnel, our business, operating results and financial condition could be harmed. Additionally, proceeds from the key person life insurance on Mr. Comstock 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

-22-

fleets we possess, our customer concentration has historically been high. Our top five customers accounted for approximately 80.7%, 81.0% and 67.4% of our revenue for the years ended December 31, 2011, 2010 and 2009, respectively. Our top ten customers represented approximately 92.7%, 90.2% and 90.6% of our revenue for the years ended December 31, 2011, 2010 and 2009, 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.

Each of our hydraulic fracturing fleets is currently working under term contracts. For the year ended December 31, 2011, we derived 68.6% of our total revenues from those term contracts. The terms of these contracts range from one to three years and two of our six contracts are set to expire in mid-2012. We may not be able to extend any of our 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 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, 2011, our net income increased $160.9 million from $1.1 million to $162.0 million and our revenues increased $696.1 million from $62.4 million to $758.5 million. We believe that our future success depends on our ability to manage the rapid organic growth that we have experienced and are expected to continue to experience upon delivery of our three on-order hydraulic fracturing fleets and 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, including potential delays with respect to our three on-order fracturing fleets; and

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

In addition, in the future we may seek to grow our business through acquisitions that enhance our existing operations. The success of any completed acquisition, including our acquisition of Total in April 2011, 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.

-23-

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 more desirable 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 must 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. We may not be able to finance future growth of our operations or future acquisitions.

Prior to our IPO, we historically funded the growth of our operations and equipment purchases from bank debt, capital contributions from our equity sponsors and cash generated by our business. If we do not generate sufficient cash from operations to expand our business, our growth could be limited unless we are able to obtain additional capital through equity or debt financings or bank borrowings. 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

-24-

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 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 $100.0 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. Please read “Note 2 – Long-Term Debt” in Part II, Item 8 “Financial Statements.”

Failure to establish and 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. We are not required to make our first assessment of our internal control over financial reporting until our annual report on Form 10-K for the year ended December 31, 2012, the year following our first annual report required to be filed with the SEC (this 10-K). We are in the process of upgrading our systems, including information technology,

-25-

implementing additional financial and management controls, reporting systems and procedures and hiring additional accounting, finance and legal staff. Implementing these requirements may occupy a significant amount of time of our Board of Directors and management and significantly increase our costs and expenses.

Our efforts to develop and 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 in Louisiana and parts of Texas may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our well completion services. 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.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHGs 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

-26-

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.

-27-

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

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 new 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 occupy a significant amount of time of our Board of Directors and management and will significantly increase our costs and expenses. We will need to:

-28-

• 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 of Directors, 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 24, 2012, we had 51,889,242 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, including the resulting decrease in the Sponsors’ collective ownership to below 25%, we opted to be governed by Section 203 of the Delaware General Corporation Law. 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

-29-

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.

-30-

Item 2. Properties

Our corporate headquarters are located at 10375 Richmond Avenue, Suite 2000, Houston, Texas 77042. We lease 24,365 square feet of general office space at our corporate headquarters. The lease expires on January 31, 2017.

As of February 24, 2012, 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	July 31, 2013
6913 N. FM 1788 Midland, TX 79707	Yard	36.25 acres	Owned	-
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	-
500 N. Shoreline Blvd, Ste.350 Corpus Christi, TX 78401	General office space	7,685 sq. ft. of building space	Leased	July 31, 2015
3205 Hwy 44 Robstown, TX 78380	General office space, warehouse & storage	6.86 acres	Leased	July 18, 2016
1130 S. US 77 Robstown, TX 78380	General office space, storage	4.55 acres	Leased	February 28, 2013
5717 US Hwy 277 Carrizo Springs, TX 78834	Yard	5 acres	Leased	July 22, 2014
214 W. 13th St. Elk City, OK 73644	General office space, warehouse & repair facility	1.85 acres, 9,000 sq.ft. of building space	Leased	January 14, 2013

All of the properties listed above, other than the property located in Granbury, Texas, are utilized by our Stimulation and Well Intervention Services business. The listed property in Granbury

-31-

Texas is maintained by Total for our 58,500 square feet manufacturing and service facility. Following our acquisition of Total, we acquired approximately 10 acres of property adjacent to Total’s current facility and began construction of an approximate 36,000 square foot manufacturing facility, which was completed in December 2011. The total cost of construction of the facility was approximately $2.0 million. We are currently utilizing the facility to manufacture new equipment and we expect to be at full capacity by mid-2012.

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 facilities are adequate for our operations and their locations allow us to efficiently serve our customers in the South Texas, East Texas/North Louisiana, West Texas and Western Oklahoma regions. We do not believe that any single facility 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. Our management does not expect the outcome in any of these known legal proceedings, individually or collectively, to have a material adverse effect on our consolidated financial condition or results of operations.

Item 4. Mine Safety Disclosures

Not applicable.

-32-

PART II

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

Market Price for Registrant’s Common Equity

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

On February 24, 2012, we had 51,889,242 shares of common stock outstanding. The common shares outstanding at February 24, 2012 were held by approximately 213 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
Period from January 1, 2012 to February 24, 2012	$	23.11	$	16.05
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

On February 24, 2012, the last reported sales price of our common stock on the NYSE was $21.87 per share.

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 of Directors 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. 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Description of Our Indebtedness.”

Unregistered Sales of Equity Securities

None.

-33-

Item 6. Selected Financial Data

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 and charges and credits, which may affect the comparability of the Selected Financial Data:

	Years Ended December 31,
	2011		2010		2009			2008		2007
	(In thousands except per share amounts)									(unaudited)
Revenue	$	758,454	$	244,157	$	67,030		$	62,441	$	28,022
Net income (loss)		161,979		32,272		(2,430	)		1,121		(723	)
Net income (loss) per common share
Basic		3.28		0.70		(0.05	)		0.02		(0.02	)
Diluted		3.19		0.67		(0.05	)		0.02		(0.02	)
Total assets		537,849		226,088		150,231			155,212		133,711
Long-term debt and capital lease obligations, excluding current portion		-		44,817		60,668			25,041		56,773

-34-

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 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 and pressure pumping services with a focus on complex, technically demanding well completions. In addition, through our subsidiary Total, we manufacture and repair equipment for our internal needs as well as for third party companies in the energy services industry.

We operate in what we believe to be some of the most geologically challenging basins in South Texas, East Texas/North Louisiana, Western Oklahoma and West Texas/East New Mexico. We are in the process of acquiring additional hydraulic fracturing fleets and are evaluating opportunities with existing and new customers to expand our operations into new areas throughout the United States with similarly demanding completion and stimulation requirements.

Recent Developments

Delivery and Deployment of Fleet 6. In December 2011, we took delivery of the first part of our sixth hydraulic fracturing fleet, which we call Fleet 6A, and deployed it immediately for operations in the Permian Basin pursuant to a two-year term contract on a full month take-or-pay basis. Fleet 6A, which consists of 16,000 horsepower, has been continuously utilized for vertical completions since deployment. Originally Fleet 6B, making up the other part of Fleet 6, was to be a 16,000 horsepower vertical fleet, but, at our customer’s request, was increased to 32,000 horsepower with the necessary ancillary equipment and deployed effective February 13, 2012 for horizontal completions in the Permian Basin.

New Equipment Purchases. We have ordered three new hydraulic fracturing fleets, Fleets 7, 8 and 9. We anticipate taking delivery of Fleet 7 in April 2012 and deploying it soon thereafter for work in the Permian Basin. Fleet 8 is anticipated for delivery in the third quarter of 2012 but may be accelerated based on market conditions. Due to the robust nature of our internal cash flow and the confidence we have in our ability to expand our customer base, we have ordered Fleet 9, which we expect to receive and deploy by the end of the fourth quarter of 2012. We are actively seeking to secure multi-year take-or-pay contracts for Fleets 7, 8 and 9; although, we believe that the equipment can attract solid demand in the spot market if long-term contracts are not secured.

During 2011, we increased our coiled tubing fleet and the associated ancillary equipment by approximately 40%, expanding from a fleet of 13 units at the beginning of the year to a fleet of 18 units by the end of the year. We have ordered six new coiled tubing units together with the related ancillary equipment, which we expect to deploy in 2012 in new basins. Historically, we have successfully leveraged our existing relationships with coiled tubing customers to expand our fracturing business and we hope to do the same as we expand our coiled tubing operations into new basins in 2012.

-35-

Initial Public Offering.On July 28, 2011, our registration statement on Form S-1 (File No. 333-173177) relating to our initial public offering of 13,225,000 shares of our common stock was declared effective by the SEC. The IPO closed on August 3, 2011, at which time we issued and sold 4,300,000 shares and selling stockholders 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 shares were sold at a price to the public of $29.00 per share. We received cash proceeds of approximately $112.1 million from this transaction, net of underwriting discounts, commissions and transaction costs. We did not receive any proceeds from the sale of shares by the selling stockholders.

Expansion of Total.On April 28, 2011, we acquired Total, a manufacturer of hydraulic fracturing, coiled tubing, pressure pumping and other equipment used in the energy services industry and one of our largest suppliers of machinery and equipment. In addition to equipment manufacturing, through Total we also conduct equipment repair services and provide other oilfield parts and supplies for third-party customers in the energy services industry as well as to meet our own internal needs. Following our acquisition of Total, we acquired approximately 10 acres of property adjacent to Total’s current facility and began construction of an approximate 36,000 square foot manufacturing facility, which was completed in December 2011. The total cost of construction of the facility was approximately $2.0 million. We are currently utilizing the facility to manufacture new equipment and we expect to be at full capacity by mid-2012.

How We Generate Our Revenues

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.

Our revenues are derived primarily from three sources:

• monthly payments for the committed hydraulic fracturing fleets under term contracts as well as prevailing market rates for spot market work, together with associated charges or handling fees for chemicals and proppants that are consumed during the fracturing process;

• prevailing market rates for coiled tubing, pressure pumping and other related well stimulation services, together with associated charges for stimulation fluids, nitrogen and coiled tubing materials; and

• sales of manufactured equipment, parts and supplies and repair services provided through our recently acquired subsidiary, Total, a manufacturer of hydraulic fracturing, coiled tubing, pressure pumping and other equipment used in the energy services industry.

Stimulation and Well Intervention Services Segment

Our Stimulation and Well Intervention Services segment encompasses three related service lines providing hydraulic fracturing, coiled tubing and pressure pumping services, with a focus on complex, technically demanding well completions.

Hydraulic Fracturing. Approximately 82% of our consolidated revenues for the year ended December 31, 2011 were derived from hydraulic fracturing services. Each of our hydraulic fracturing fleets are currently working under term contracts: Fleets 1 and 2 are dedicated through mid-2012 to

-36-

producers operating in the Eagle Ford Shale; Fleet 3 is dedicated through early 2013 to a producer operating in the Eagle Ford Shale; Fleet 4 is dedicated through mid-2014 to a producer operating in the Haynesville Shale; Fleet 5 is dedicated through mid-2013 to a producer operating in the Eagle Ford Shale; and Fleet 6 is dedicated through late 2013 to a producer operating in the Permian Basin. Fleet 4 remains under contract but has been redeployed to the Eagle Ford for committed work, with spot market availability for new customers working in the Eagle Ford Shale, as well as the Permian Basin. The customer relationship remains in place and this fleet may be redeployed to the Haynesville Shale at the election of the contract customer with timely notice. We are scheduled to take delivery of Fleets 7, 8 and 9 in April 2012, the third quarter of 2012 and the fourth quarter of 2012, respectively. We are seeking to secure multi-year take-or-pay contracts for Fleets 7, 8 and 9, and to renew the two contracts that are set to expire in mid-2012, although, we believe that the equipment can attract solid demand in the spot market if long-term contracts are not secured.

Our term contracts generally range from one year to three years. Under the term contacts, typically our customers are 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. Our term contracts typically 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.

Although our term contracts provide some visibility on anticipated future minimum asset utilization, they do not provide us with sufficient certainty to present backlog information on an ongoing basis. Unlike long-term contracts for equipment or services at fixed prices or on a day rate or turnkey basis, where future revenue or earnings can be reliably forecasted based on the dollar amount of backlog believed to be firm, future revenues generated from our term contracts are subject to a number of variables that prevent us from providing similar information with any degree of certainty. Under our term contracts, we derive revenues from:

• mandatory monthly payments for a specified minimum number of hours of service per month;

• preset amounts for each hour of service in excess of the contracted minimum number of hours of service per month; and

• preset service charges for chemicals and proppant materials that are consumed during the fracturing process.

Given these variables, revenues from our term contracts vary substantially from customer to customer and from month to month depending on the number of hours of services actually provided, the amount of chemicals and proppant materials consumed and whether we or the customer supplies the sand. Generally, when we exceed the number of hours of service included in our base monthly rate, we consume more chemicals and proppants and provide additional pumping and related services to complete the project, each of which will significantly impact our revenues. Mandatory monthly payments under our term contracts have historically accounted for less than half of our total revenues.

Although we have entered into term contracts for each of our existing hydraulic fracturing fleets, we also have the flexibility to pursue spot market projects. Some of our term contracts allow us to supplement monthly contract revenue by deploying equipment on short-term spot market jobs on those days when the contract customer does not require our services or is not entitled to our services under the applicable term contract. We charge prevailing market prices per hour for spot market work.

-37-

We may also charge fees for setup and mobilization of equipment depending on the job. 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 sand. We believe our ability to provide services in the spot market allows us to take advantage of any favorable pricing that may exist in this market and allows us to develop new customer relationships.

Coiled Tubing and Pressure Pumping. Our coiled tubing, pressure pumping and other related well intervention 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.

Equipment Manufacturing Segment.

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 segment 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 our internal needs.

How We Manage Costs and Maintain Our Equipment

The principal expenses involved in conducting our business are costs for chemicals, proppants and other materials, labor expenses, costs for maintenance and repair of our equipment, costs to replace tubing on our coiled tubing units, depreciation expenses and fuel costs. Additionally, we incur freight costs to deliver and stage chemicals and proppants to the worksite. Proppant, chemical and associated freight costs represented approximately 31.8% and 34.7% of our revenues for the years ended December 31, 2011 and 2010, respectively. Direct labor costs represented approximately 8.7% and 10.7% of our revenues for the years ended December 31, 2011 and 2010, respectively. Repair and maintenance costs represented approximately 7.9% and 6.3% of our revenues for the years ended December 31, 2011 and 2010, respectively. Tubing replacement costs represented approximately 1.8% and 3.6% of our revenues for the years ended December 31, 2011 and 2010, respectively. Depreciation costs represented approximately 2.5% and 4.0% of our revenues for the years ended December 31, 2011 and 2010, respectively. We also incur significant fuel costs in connection with the operation of our hydraulic fracturing fleets and the transportation of our equipment and products.

We maintain and repair all equipment we use in our operations. We primarily purchase replacement components for our equipment, including engines, transmissions, radiators, motors and pumps, from third-party vendors. Our acquisition of Total in April 2011, which has historically been one of our largest suppliers of machinery and equipment, provides several strategic advantages, including a significant reduction in our exposure to third-party supply chain constraints, shorter cycle

-38-

times for the delivery of new equipment and some replacement parts, a reduction in and greater control of the cost of new equipment, and enhanced operational control of our service offerings. Furthermore, the acquisition of Total is expected to help minimize downtime by enhancing our capabilities for maintenance and repair of our hydraulic fracturing equipment. Total is currently constructing the hydraulic fracturing pumps for all three of our on-order fleets and all six of our on-order coiled tubing units.

How We Manage Our Operations

Our management team uses a variety of tools to monitor and manage our operations in the following four areas: (1) asset utilization, (2) equipment maintenance performance, (3) customer satisfaction and (4) safety performance.

Asset Utilization. We measure our activity levels by the total number of jobs completed by each of our hydraulic fracturing fleets and coiled tubing units on a monthly basis. By consistently monitoring the activity level, pricing and relative performance of each of our fleets and units, we can more efficiently allocate our personnel and equipment to maximize revenue generation.

Our hydraulic fracturing business contributed $619.8 million of revenue and completed 3,713 fracturing stages during the year ended December 31, 2011, compared to $182.7 million of revenue and 1,038 fracturing stages for the previous year. During the year ended December 31, 2011, we averaged monthly revenue per unit of horsepower of $374 compared to $336 for the previous year.

Our coiled tubing business contributed $97.2 million of revenue and we completed 3,183 coiled tubing jobs during the year ended December 31, 2011, compared to $50.6 million of revenue and 2,084 coiled tubing jobs for the previous year. We entered 2011 with a fleet of 13 coiled tubing units, and took delivery of five units during the year, ending with a fleet of 18 coiled tubing units.

Our pressure pumping business generated $19.4 million of revenue during the year ended December 31, 2011, up from $10.9 million during the year ended December 31, 2010.

Equipment Maintenance Performance. Preventative maintenance on our equipment is an important factor in our profitability. If our equipment is not maintained properly, our repair costs may increase and, during periods of high activity, our ability to operate efficiently could be significantly diminished due to having trucks and other equipment out of service. Our maintenance crews perform regular inspections and preventative maintenance on each of our trucks and other mechanical equipment. Our management monitors the performance of our maintenance crews at each of our service centers by reviewing ongoing inspection and maintenance activity and monitoring the level of maintenance expenses as a percentage of revenue. A rising level of maintenance expenses as a percentage of revenue at a particular service center can be an early indication that our preventative maintenance schedule is not being followed. In this situation, management can take corrective measures to help reduce maintenance expenses as well as ensure that maintenance issues do not interfere with operations.

Customer Satisfaction. Upon completion of each job, we encourage our customers to provide feedback on their satisfaction level. Customers evaluate our performance under various criteria and comment on their overall satisfaction level. This feedback gives our management valuable information from which to identify performance issues and trends. Our management also uses this information to evaluate our position relative to our competitors in the various markets in which we operate.

-39-

Safety Performance.Maintaining a strong safety record is a critical component of our operational success. Many of our larger customers have safety standards we must satisfy before we can perform services for them. We maintain a safety database so that our customers can review our historical safety record. Our management also uses this safety database to identify negative trends in operational incidents so that appropriate measures can be taken to maintain and enhance our safety standards.

Our Challenges

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, we believe that we are well positioned to capitalize on the current growth opportunities available in the industry in which we operate. However, we may be unable to capitalize on our competitive strengths to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read 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.

Equipment Supply. The overall number of equipment suppliers in the industry in which we operate is limited, and there has historically been high demand for this equipment. This limited capacity of supply increases the risk of delay and failure to timely deliver both our on-order equipment and any future equipment that may be necessary to grow our business. We expect to take delivery of three new hydraulic fracturing fleets, Fleets 7, 8 and 9, in April 2012, in the third quarter of 2012 and in the fourth quarter of 2012, respectively. In addition, we have ordered six new coiled tubing units along with related ancillary equipment and we expect to take delivery of each of these new units in 2012. To mitigate the risk of a potential delay in equipment delivery, we actively monitor the progression of the production schedule of our on-order equipment. Our recent acquisition of Total, a significant supplier of our hydraulic fracturing and coiled tubing equipment, has provided us with added monitoring capabilities and control over access to, and delivery of, new equipment.

Hydraulic Fracturing Legislation and Regulation. Congress has from time to time, including during the current session, considered legislation to provide for federal regulation of hydraulic fracturing and to require public disclosure of the chemicals used in the fracturing process. If such current or any future federal legislation becomes law, it could establish an additional level of regulation that could lead to operational delays or increased operating costs. The EPA also recently proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Among other controls, the rules would require operators to use “green completions” for hydraulic fracturing, meaning operators would have to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing, and Texas has adopted legislation that requires disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public.

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

-40-

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.

Financing Future Growth. Historically, we have funded our growth through bank debt, capital contributions and borrowings from our stockholders, and cash generated from our business. The successful execution of our growth strategy depends on our ability to raise capital as needed to, among other things, finance the purchase of additional hydraulic fracturing fleets. 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 April 19, 2011, we entered into a five-year $200.0 million senior secured revolving credit facility. In addition, our cash flows from operations have continued to increase, with cash flows from operations during the year ended December 31, 2011 increasing by $127.0 million from the same period in 2010. We believe that the combination of our cash on hand, which is $49.8 million as of February 24, 2012, our cash flows from operations and available borrowings under our credit agreement will be sufficient to allow us to sustain or increase our current growth through 2012.

Outlook

Demand for our services has increased significantly over the last two years in the markets in which we operate and we have made substantial investments in the acquisition of additional equipment in order to capitalize on this market opportunity, which has led to significant growth in our business. We believe the following trends impacting our industry have increased the demand for our services and will continue to support the sustained growth that we have experienced to date:

• ongoing development of existing and emerging unconventional resource basins;

• increased horizontal drilling and greater service intensity in unconventional resource basins, particularly in oily- and liquids-rich formations where we are seeing enhanced economics, through the application of completion technologies such as hydraulic fracturing;

• improved drilling efficiencies increasing the number of horizontal feet per day requiring completion services; and

• increased hydraulic fracturing intensity, particularly with increasingly longer laterals and a greater number of fracturing stages per well, in more demanding and technically complex formations.

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. Because we typically pass the cost of raw materials, such as proppants and chemicals, onto our customers, our profitability is not 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 have entered into term contracts covering each of our six existing fleets. We are seeking to secure multi-year take-or-pay contracts for Fleets 7, 8 and 9; although, we believe that the equipment can attract solid demand in the spot market if long-term contracts are not secured.

-41-

We expect that our revenues and results of operations will continue to be positively impacted by: (1) the addition and deployment of Fleet 4 in April 2011; (2) the addition and deployment of Fleet 5 in August 2011; (3) the addition and deployment of Fleet 6A in December 2011 and Fleet 6B in February 2012; and (4) the acquisition of Total in April 2011. In the near term, we also expect our revenues and results of operations to be positively impacted by the deployment of Fleets 7, 8 and 9 in April 2012, the third quarter of 2012 and the fourth quarter of 2012, respectively. Our results of operations in 2011 compared to 2010 were significantly impacted by the dramatic growth of our asset base over the last twelve months.

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
Cost of sales		443,556		154,297		289,259
Gross profit		314,898		89,860		225,038
Selling, general and administrative expenses		52,737		17,998		34,739
(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 same period in 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 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.

-42-

Cost of Sales

Cost of sales increased $289.3 million, or 188%, to $443.6 million for the year ended December 31, 2011, compared to $154.3 million for the same period in 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 $34.7 million, or 193%, to $52.7 million for the year ended December 31, 2011, as compared to $18.0 million for the same period in 2010. The increase primarily related 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 $5.3 million in increased SG&A costs associated with Total in 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 same period in 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 senior 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 senior credit facility and subordinated term loan. Immediately following these extinguishments, we entered into a new $200.0 million senior secured revolving credit facility. Please read “—Description of Our Indebtedness” below for further discussion.

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 expect to take 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.

-43-

Results for the Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

The following table summarizes the change in our results of operations for the year ended December 31, 2010 when compared to the year ended December 31, 2009 (in thousands):

	Years Ended December 31,
	2010		2009		$ Change
Revenue	$	244,157	$	67,030	$	177,127
Cost of sales		154,297		54,242		100,055
Gross profit		89,860		12,788		77,072
Selling, general and administrative expenses		17,998		9,533		8,465
Loss on disposal of assets		1,571		920		651
Operating income		70,291		2,335		67,956
Other income (expense):
Interest expense, net		(17,341)		(4,708)		(12,633)
Other income (expense)		(309)		(443)		134
Total other expenses		(17,650)		(5,151)		(12,499)
Income (loss) before income taxes		52,641		(2,816)		55,457
Provision (benefit) for income taxes		20,369		(386)		20,755
Net income (loss)	$	32,272	$	(2,430)	$	34,702

Revenue

Revenue increased $177.1 million, or 264%, to $244.2 million for the year ended December 31, 2010 as compared to $67.0 million for the same period in 2009. This increase was due primarily to increased utilization of our hydraulic fracturing and coiled tubing equipment and, to a lesser extent, improved pricing for our services and the deployment of Fleet 2 in the third quarter of 2010, which contributed $67.6 million of revenue during the year. 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 of the work performed in these areas.

Cost of Sales

Cost of sales increased $100.1 million, or 184%, to $154.3 million for the year ended December 31, 2010 as compared to $54.2 million for the same period in 2009. As a percentage of revenue, cost of sales decreased to 63% for the year ended December 31, 2010 from 81% for the same period in 2009 due primarily to the significant increase in our revenues from 2009 to 2010.

Selling, General and Administrative Expenses (SG&A)

SG&A increased $8.5 million, or 89%, to $18.0 million for the year ended December 31, 2010 as compared to $9.5 million for the same period in 2009. The increase primarily related to $4.0 million in higher long-term and short-term incentive costs and $2.3 million in higher payroll and personnel

-44-

costs associated with the continued hiring of personnel to support our growth. We also incurred $0.7 million in additional costs associated with our marketing and promotional efforts and $0.5 million in increased professional fees.

Interest Expense

Interest expense increased by $12.6 million, or 268%, to $17.3 million for the year ended December 31, 2010 as compared to $4.7 million for the same period in 2009. This increase was due primarily to $10.1 million in increased charges in connection with the change in fair value of our warrant liability during the year. Also contributing to the increase in interest expense was approximately $2.2 million related to higher average interest rates during 2010 as compared to 2009.

Income Taxes

We recorded a tax provision of $20.4 million for the year ended December 31, 2010, at an effective rate of 38.7%, compared to a tax benefit of $386,000 for the year ended December 31, 2009, at an effective rate of 13.7%. For the year ended December 31, 2009, we incurred intangible amortization expense for book purposes that was non-deductible for federal income tax purposes, giving way to a lower effective benefit rate during the year.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from stockholders, the net proceeds that we received from our recent IPO, borrowings under our credit facilities and cash flows from operations. Our primary use of capital has been the acquisition and maintenance of equipment. During 2009, we spent significantly less on capital expenditures than we had in previous years. Our capital expenditures increased in 2010 and 2011 and we anticipate capital expenditures will continue to increase through 2012. We have ordered three new hydraulic fracturing fleets, Fleets 7, 8 and 9, which are scheduled for delivery in April 2012, the third quarter of 2012 and the fourth quarter of 2012, respectively. Fleet 7 has an aggregate cost of approximately $26 million, of which approximately $17.2 million had been funded as of February 24, 2012. Fleet 8 has an aggregate cost of approximately $29 million, of which approximately $1.5 million had been funded as of February 24, 2012. Fleet 9 has an aggregate cost of approximately $30 million, of which approximately $0.7 million had been funded as of February 24, 2012. In addition, we have ordered six new coiled tubing units along with related ancillary equipment for delivery in 2012 with a combined aggregate cost of approximately $20 million, of which approximately $0.5 million has been funded as of February 24, 2012. We intend to fund the remaining costs of the three hydraulic fracturing fleets and six coiled tubing units through a combination of cash on hand, which is $49.8 million as of February 24, 2012, cash flows from operations, and, to the extent necessary, borrowings under our credit facility.

On April 19, 2011, we entered into a five-year $200.0 million revolving credit facility, which we refer to as the credit facility. Proceeds from the closing of the credit facility were used to repay $49.6 million of indebtedness outstanding under our previous revolving credit facility and $29.9 million of indebtedness, accrued interest and early termination penalties under our subordinated term loan. The majority of proceeds we received from our IPO were used to pay down all amounts outstanding under our credit facility and, as such, we have no balance outstanding as of February 24, 2012.

-45-

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 and existing capital coupled with borrowings available under our credit facility will be adequate to meet operational and capital expenditure needs for at least the next 12 months.

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. These covenants are subject to a number of exceptions and qualifications set forth in the credit agreement that evidences such credit facility. We are currently in compliance with these covenants. In addition, our credit facility contains covenants that limit our ability to make capital expenditures in excess of $100.0 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 our common stock or to maintenance capital expenditures. The credit facility also restricts our ability to incur additional debt or sell assets, make certain investments, loans and acquisitions, guarantee debt, grant liens, enter into transactions with affiliates, engage in other lines of business and pay dividends and distributions. For more information concerning the credit facility, please read “—Description of Our Indebtedness.”

Capital Requirements

The energy services business is capital-intensive, requiring significant investment to expand, upgrade and maintain equipment. Our capital requirements have consisted primarily of, and we anticipate will continue to be:

• growth capital expenditures, such as those to acquire additional equipment and other assets or upgrade existing equipment to grow 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 equipment and down-hole technology, as well as technologies that may complement our existing businesses, and commit capital funds to upgrade and purchase additional equipment to meet our customers’ needs. Our total 2011 capital expenditures were $140.7 million, including approximately $111 million for our hydraulic fracturing fleets and approximately $23 million for our coiled tubing spreads. In 2012, we plan to spend approximately $145 to $160 million on capital expenditures, including $125 million on the hydraulic fracturing fleets and $20 million on the coiled tubing spreads that are on order for delivery this year.

Historically, we have primarily grown through organic expansion and with the acquisition of Total we enhanced our manufacturing and repair capabilities through vertical integration. We will continue to evaluate opportunities to expand our business through selective acquisitions and make capital investment decisions that we believe will support our long-term growth strategy. We plan to continue to monitor the economic environment and demand for our services and adjust our business strategy as necessary.

-46-

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,
	2011		2010		2009
Cash flow provided by (used in):
Operating activities	$	171,702	$	44,723	$	12,056
Investing activities		(165,545)		(43,818)		(4,254)
Financing activities		37,806		734		(6,733)
Net change in cash and cash equivalents	$	43,963	$	1,639	$	1,069

Cash Provided by Operating Activities

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 is 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 is 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 is primarily attributable to increases in accounts receivable, net of increases in various payable items, as a result of the growth of our business.

Net cash provided by operating activities increased $32.7 million for the year ended December 31, 2010 compared to the year ended December 31, 2009. This increase was primarily due to an increase in net income of $34.7 million. The significant changes in working capital requirements primarily related to accounts receivable, corresponding to changes in revenue.

Cash Flows Used in Investing Activities

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. Cash used in investing activities also increased during 2011 by $27.2 million as a result of our acquisition of Total.

Net cash used in investing activities increased $39.6 million for the year ended December 31, 2010 compared to the year ended December 31, 2009. This increase was due to higher capital expenditures related to the growth of our hydraulic fracturing business. Our overall capital expenditures plan in 2009 was decreased due to the decline in commodity prices and the resultant decline in activity levels.

-47-

Cash Flows Provided by (Used in) Financing Activities

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. The increase was primarily due to net proceeds from our IPO, partially offset by repayment of long-term debt.

Net cash provided by financing activities was $0.7 million for the year ended December 31, 2010 compared to net cash used in financing activities of $6.7 million for the year ended December 31, 2009. The increase in cash provided by financing activities was largely due to the increased borrowings under our credit facility during 2010, primarily to fund working capital requirements and capital expenditures, partially offset by debt repayments in the first half of 2010 to our previous lenders. During the year ended December 31, 2009, we repaid long-term borrowings under our debt facilities totaling $8.7 million and raised $2.0 million in borrowings from our Sponsors and management.

Contractual Obligations

The following table summarizes our contractual cash obligations as of December 31, 2011 (in thousands):

Contractual Obligation	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Credit facility	$	-	$	-	$	-	$	-	$	-
Operating leases		15,965		5,547		8,931		1,437		50
Vendor supply agreements		56,618		26,268		30,350		-		-
Total	$	72,583	$	31,815	$	39,281	$	1,437	$	50

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, 2011.

Description of Our Indebtedness

Senior Secured Credit Agreement. On April 19, 2011, we entered into a new 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. Our obligations under our credit facility are guaranteed by our Subsidiaries, Spec-Rent Services and Total. Our credit facility enables us to borrow funds on a revolving basis for working capital needs and also provides for the issuance of letters of credit. In addition, we may request additional commitments of up to $75.0 million through an incremental facility upon the satisfaction of certain conditions. Up to the entire credit facility amount may be drawn as letters of credit, and the credit facility has a sublimit of $15.0 million for swing line loans. As of February 24, 2012, there were no amounts outstanding under our credit facility, leaving the entire $200.0 million available for borrowing.

-48-

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 leverage ratio. The leverage ratio is the ratio of funded indebtedness to EBITDA, as deined in the credit facility, for us and our subsidiaries on a consolidated basis.

All obligations under our credit facility are secured, subject to agreed upon exceptions, by a first priority perfected security interest on all of our real and personal property and that of our Subsidiaries, as guarantors.

Voluntary prepayments are permitted under the terms of our credit facility at any time without penalty or premium.

Our credit facility provides for payment of certain fees and expenses, including (1) a fee on the revolving loan commitments which varies depending on our leverage ratio, (2) a letter of credit fee on the stated amount of issued and undrawn letters of credit and a fronting fee to the issuing lender, and (3) other customary fees, including an agency fee.

Our credit facility contains, among other things, restrictions on our and our guarantors’ ability to consolidate or merge with other companies, conduct asset sales, incur additional indebtedness, grant liens, issue guarantees, make investments, loans or advances, pay dividends, enter into certain transactions with affiliates and to make capital expenditures in excess of $100.0 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, among other things, capital expenditures financed solely with proceeds from the issuance of common equity interests or to normal replacement and maintenance capital expenditures.

Our credit facility contains customary affirmative covenants including financial reporting, governance and notification requirements. Our 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 “Leverage Ratio” of not greater than 3.25 to 1.00 as such terms are defined in our credit facility. We are currently in compliance with all debt covenants.

Our credit facility provides that, upon the occurrence of events of default, our obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include, among other things, payment defaults to lenders, failure to meet covenants, material inaccuracies of representations or warranties, cross defaults to other indebtedness, insolvency, bankruptcy, Employee Retirement Income Security Act (“ERISA”) and judgment defaults, and change in control, which includes (1) a change in control under certain unsecured indebtedness issued by us or our Subsidiaries, (2) a person or group other than certain permitted holders becoming the beneficial owner of 35% or more of our voting securities, or (3) our Board of Directors being comprised for a period of 18 consecutive months of individuals who were neither members at the beginning of such period nor approved by individuals who were members at the beginning of such period.

Each loan and issuance of a letter of credit under the credit facility is subject to the conditions that the representations and warranties in the loan documents remain true and correct in all material respects and no default or event of default shall have occurred or be continuing at the time of or immediately after such borrowing or extension of a letter of credit.

-49-

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 U.S. GAAP. The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, expenses and related disclosures. We base our estimates and assumptions on historical experience and on various other factors that we believe to be reasonable under the circumstances. We evaluate our estimates and assumptions on an ongoing basis. The results of our analysis form the basis for making assumptions about the carrying values of assets and liabilities that are not readily apparent from other sources. Our actual results may differ from these estimates under different assumptions or conditions.

We believe the following critical accounting policies involve significant areas of management’s judgments and estimates in the preparation of our consolidated financial statements.

Property, Plant and Equipment.Property, plant and equipment is recorded at cost less accumulated depreciation. Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to expense when incurred. Refurbishments and renewals are capitalized when the life of the equipment is 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 $19.3 million and $9.7 million for the years ended December 31, 2011 and 2010, respectively.

Goodwill, Intangible Assets and Amortization. In accordance with Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”) Topic 350,Intangibles – Goodwill and Other (“FASB ASC 350”),as amended in September 2011,goodwill is not amortized, but instead is assessed at least annually for indicators of impairment. Based on qualitative factors, we make a determination as to whether or not we believe the fair value of the reporting unit(s) associated with our goodwill will exceed the carrying value of such reporting unit, based on a more-likely-than-not threshold (defined as a greater than 50% likelihood). If we believe the probability that the fair value of our reporting unit(s) exceeding the carrying value of the reporting unit is 50% or lower then we will proceed to the two-step impairment test as outlined in FASB ASC 350. The two-step impairment test requires that we allocate the carrying value of goodwill and all other assets and liabilities to our reporting units. Our impairment tests involve the use of different valuation techniques, including a combination of the income and market approach, to determine the fair value of each reporting unit. Determining the fair value of a reporting unit is a matter of judgment and often involves the use of significant estimates and assumptions. If the fair value of the reporting unit is less than its carrying value, an impairment loss is recorded to the extent that the implied fair value of the reporting unit’s goodwill is less than its carrying value. 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.

-50-

Intangible assets with indefinite lives are not amortized, but instead tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Our annual impairment tests involve the use of different valuation techniques, including a combination of the income and market approach, to determine the fair value of our intangible assets. Determining the fair value of intangible assets is a matter of judgment and often involves the use of significant estimates and assumptions. If the fair value of our intangible assets is less than the carrying value, an impairment loss is recorded.

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.

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.

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. We only enter into arrangements with customers for which we believe that collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or numerous 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. With respect to services performed under term contracts, customers are invoiced a monthly mandatory payment based on a specified minimum number of hours of service per month as defined in the contract, whether or not those services are actually utilized, upon the earlier of the passage of time or completion of the job. To the extent customers utilize more than the contracted minimum number of hours of service per month, they are invoiced for such excess at rates defined in the contract upon the completion of each job.

Coiled Tubing and Pressure Pumping Revenue. We enter into arrangements to provide coiled tubing and pressure pumping services to only those customers for which we believe that collectability

-51-

is reasonably assured. These arrangements are typically short-term in nature and each job can last anywhere from a few hours to multiple days. Coiled tubing and pressure pumping 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. When we source the chemicals and proppants, we charge fees to our customers based on the amount of chemicals and proppants used in providing these services. If our customer sources the chemicals or proppants, we charge our customers a handling fee for the chemicals and proppants consumed in the process. In addition, ancillary to coiled tubing and pressure pumping revenue, we generate revenue from various fluids and supplies that are necessarily consumed during those processes. We do not sell or otherwise charge a fee separate and apart from the services we provide for any of the materials consumed while performing hydraulic fracturing, coiled tubing or pressure pumping services.

Equipment Manufacturing Revenue.We enter into arrangements to construct equipment for only those customers for which we believe that collectability is reasonably assured. Revenue is recognized and the customer is invoiced upon the completion and delivery of each order to the customer.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at the amount billed to customers and are ordinarily due upon receipt. We provide an allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Provisions for doubtful accounts are recorded when it is deemed probable that the customer will not make the required payments at either contractual due dates or in the future. The allowance for doubtful accounts totaled $0.8 million at December 31, 2011 and $0.5 million at December 31, 2010. Bad debt expense was $0.4 million and $0.5 million for the years ended December 31, 2011 and 2010, respectively.

Stock-Based Compensation.We recognize compensation expense related to stock-based awards based on the estimated fair value at grant date. We amortize the fair value of stock options on a straight-line basis over the requisite service period of the award, which is generally the vesting period. The determination of the fair value of stock options is estimated using the Black-Scholes option-pricing model and 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

-52-

and longer expected terms generally result in an increase to stock-based compensation expense determined at the date of grant.

Income Taxes. Income taxes are provided for the tax effects of transactions reported in financial statements and consist of taxes currently due plus deferred taxes. 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.

Deferred income tax expense represents the change during the period in the deferred tax assets and deferred tax liabilities.

The components of the deferred tax assets and liabilities are individually classified as current and non-current based on their characteristics. Deferred tax assets are reduced by a valuation allowance 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.

Effective January 1, 2009, we adopted guidance issued by the FASB ASC Topic 740,Income Taxes, in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the financial statements and applies to all income tax positions. Each income tax position is assessed using a two step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. We did not recognize any uncertain tax positions upon adoption of the guidance and had no uncertain tax positions as of December 31, 2011 and December 31, 2010. Management believes there are no tax positions taken or expected to be taken in the next twelve months that would significantly change our unrecognized tax benefits.

We will record income tax related interest and penalties, if applicable, 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, 2011, and 2010, respectively. The tax years that remain open to examination by the major taxing jurisdictions to which we are subject range from 2007 to 2010. We have identified our major taxing jurisdictions as the United States of America and Texas. None of our federal or state income tax returns are currently under examination.

We are subject to the Texas Margin Tax, which is determined by applying a tax rate to a base that considers both revenue and expenses. It is considered an income tax and is accounted for in accordance with the provisions of the FASB ASC Topic 740,Income Taxes.

Recently Adopted Accounting Pronouncements

In December 2010, the FASB issued Accounting Standards Update No. 2010-29, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” or

-53-

ASU 2010-29. ASU 2010-29 addresses diversity in the interpretation of pro forma revenue and earnings disclosure requirements for business combinations. If a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. We adopted ASU 2010-29 on January 1, 2011. This update had no impact on our consolidated financial statements.

In September 2011, the FASB issued Accounting Standards Update No. 2011-08, “Intangibles — Goodwill and Other” (“ASU 2011-08”). ASU 2011-08 allows a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount before applying the two-step goodwill impairment test. If it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the two-step impairment test for that reporting unit would be performed. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 and early adoption is permitted. We elected to early adopt this update to be effective for the fiscal year beginning January 1, 2011. This update changed the process that we use to determine if goodwill is impaired but did not have a material 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, 2011, 2010 and 2009. 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 energy services and equipment 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 the risk related to increases in the prices of fuel and raw materials consumed in performing our services. We are also exposed to risks related to interest rate fluctuations. We do not engage in commodity price hedging activities.

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

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, 2010 and 2009 would have resulted in an increase in interest expense and a corresponding decrease in net income of approximately $0.7 million and $0.7 million, respectively. We had no debt outstanding as of December 31, 2011.

-54-

Item 8. Financial Statements and Supplementary Data

Index to

Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm	56
Consolidated Balance Sheets as of December 31, 2011 and 2010	57
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009	58
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December  31, 2011, 2010 and 2009	59
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009	60
Notes to Consolidated Financial Statements	61

-55-

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

C&J Energy Services, Inc.

We have audited the accompanying consolidated balance sheets of C&J Energy Services, Inc. and Subsidiaries (collectively, the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2011. 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.

The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.

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, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

February 28, 2012

-56-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(AMOUNTSINTHOUSANDS,EXCEPTSHAREDATA)

	As of December 31,
	2011		2010
ASSETS
Current assets:
Cash and cash equivalents	$	46,780	$	2,817
Accounts receivable, net		122,169		44,354
Inventories, net		45,440		8,182
Prepaid and other current assets		9,138		3,768
Deferred tax assets		789		265
Total current assets		224,316		59,386
Property, plant and equipment, net		213,697		88,395
Other assets:
Goodwill		65,057		60,339
Intangible assets, net		25,419		5,768
Deposits on equipment under construction		6,235		8,413
Deferred financing costs, net of accumulated amortization of $411 at December 31, 2011 and $506 at December 31, 2010		2,528		3,190
Other noncurrent assets		597		597
Total assets	$	537,849	$	226,088
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	57,564	$	14,524
Current portion of long-term debt		-		27,222
Payroll and related costs		4,799		3,651
Accrued expenses		9,622		3,089
Income taxes payable		1,827		6,525
Customer advances and deposits		5,392		4,000
Other current liabilities		33		33
Total current liabilities		79,237		59,044
Long-term debt		-		44,817
Deferred tax liabilities		62,471		12,058
Other long-term liabilities		1,086		723
Total liabilities		142,794		116,642
Stockholders’ equity
Common stock, par value of $.01, 100,000,000 shares authorized, 51,886,574 issued and outstanding at December 31, 2011 and 47,499,074 issued and outstanding at December 31, 2010		519		475
Additional paid-in capital		201,874		78,288
Retained earnings		192,662		30,683
Total stockholders’ equity		395,055		109,446
Total liabilities and stockholders’ equity	$	537,849	$	226,088

See accompanying notes to consolidated financial statements

-57-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF OPERATIONS

(Amounts in thousands, except per share data)

	Years Ended December 31,
	2011		2010		2009
Revenue	$	758,454	$	244,157	$	67,030
Cost of sales		443,556		154,297		54,242
Gross profit		314,898		89,860		12,788
Selling, general and administrative expenses		52,737		17,998		9,533
(Gain) loss on disposal of assets		(25)		1,571		920
Operating income		262,186		70,291		2,335
Other income (expense):
Interest expense, net		(4,221)		(17,341)		(4,708)
Loss on early extinguishment of debt		(7,605)		-		-
Other income (expense), net		(40)		(309)		(443)
Total other expense, net		(11,866)		(17,650)		(5,151)
Income (loss) before income taxes		250,320		52,641		(2,816)
Income tax expense (benefit)		88,341		20,369		(386)
Net income (loss)	$	161,979	$	32,272	$	(2,430)
Net income (loss) per common share
Basic	$	3.28	$	0.70	$	(0.05)
Diluted	$	3.19	$	0.67	$	(0.05)
Weighted average common shares outstanding:
Basic		49,315		46,352		46,323
Diluted		50,780		47,851		46,323

See accompanying notes to consolidated financial statements

-58-

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, 2008		46,323	$	463	$	66,796	$	841	$	68,100
Stock-based compensation		-		-		129		-		129
Net loss		-		-		-		(2,430)		(2,430)
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
Excess tax benefit from stock-based award activity		-		-		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

See accompanying notes to consolidated financial statements

-59-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF CASH FLOWS

(Amounts in thousands)

	Years Ended December  31,
	2011		2010		2009
Cash flows from operating activities:
Net income (loss)	$	161,979	$	32,272	$	(2,430)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		22,919		10,711		9,828
Deferred income taxes		45,903		8,327		(624)
Provision for doubtful accounts, net of write-offs		415		504		200
(Gain) loss on disposal of assets		(25)		1,571		920
Loss on change in fair value of warrant liability		-		10,403		336
Stock-based compensation expense		10,846		634		129
Excess tax benefit from stock-based award activity		(512)		-		-
Non cash paid in kind interest expense		-		278		293
Amortization of deferred financing costs		703		747		319
Write-off of deferred financing costs related to early extinguishment of debt		2,899		-		-
Changes in operating assets and liabilities:
Accounts receivable		(72,323)		(32,191)		494
Inventories		(29,201)		(5,719)		(1,602)
Prepaid expenses and other current assets		(5,416)		(1,708)		165
Accounts payable		41,426		2,486		4,079
Accrued liabilities		5,366		6,708		73
Accrued taxes		(5,607)		6,254		(124)
Deferred income		(4,000)		4,000		-
Other		(3,670)		(554)		-
Net cash provided by operating activities		171,702		44,723		12,056
Cash flows from investing activities:
Purchases of and deposits on property and equipment		(140,723)		(44,473)		(4,301)
Payments made to acquire Total E&S, Inc., net of cash acquired		(27,222)		-		-
Proceeds from disposal of property and equipment		2,400		655		47
Net cash used in investing activities		(165,545)		(43,818)		(4,254)
Cash flows from financing activities:
Payments on revolving debt, net		(3,000)		(34,500)		(6,150)
Proceeds from long-term debt		12,750		75,888		2,000
Repayments of long-term debt		(81,789)		(36,920)		(2,500)
Repayments of capital lease obligations		-		(40)		(83)
Financing costs		(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		125		-		-
Excess tax benefit from stock-based award activity		512		-		-
Net cash provided by (used in) financing activities		37,806		734		(6,733)
Net increase in cash and cash equivalents		43,963		1,639		1,069
Cash and cash equivalents, beginning of year		2,817		1,178		109
Cash and cash equivalents, end of year	$	46,780	$	2,817	$	1,178
Supplemental cash flow disclosure:
Cash paid for interest	$	8,417	$	5,796	$	4,095
Cash paid for income taxes	$	46,692	$	5,748	$	396

See accompanying notes to consolidated financial statements

-60-

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. (“C&J”) was incorporated in Texas in 2006 and re-incorporated in Delaware in 2010. C&J is a holding company and substantially all of its operations are conducted through, and substantially all of its assets are held by, C&J Spec-Rent Services, Inc. (“Spec-Rent”) and Total E&S, Inc. (“Total”). C&J owns 100% of the outstanding capital stock of Spec-Rent, an Indiana corporation, and in April 2011 Spec-Rent acquired 100% of the outstanding capital stock of Total, an Indiana corporation. C&J, Spec-Rent and Total are herein collectively referred to as the “Company” and Spec-Rent and Total are herein collectively referred to as the “Subsidiaries.”

The Company provides hydraulic fracturing, coiled tubing and pressure pumping services to oil and natural gas exploration and production companies operating in basins in South Texas, East Texas/North Louisiana, Western Oklahoma and West Texas/East New Mexico. Through Total, the Company also manufactures and repairs equipment for companies in the energy services industry as well as equipment to fulfill the Company’s internal equipment demands.

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 for, 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, 2011 and 2010, the allowance for doubtful accounts totaled $0.8 million and $0.5 million, respectively. Bad debt expense was $0.4 million, $0.5 million and $0.2 million for the years ended December 31, 2011, 2010 and 2009.

Inventories. Inventories for the Stimulation and Well Intervention Services segment consist of finished goods, including spare parts to be used in maintaining equipment and general supplies and materials for the segment’s 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.

-61-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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

	As of December 31,
	2011		2010
Manufacturing parts	$	6,809	$	-
Work-in-process		7,133		-
Finished goods		31,844		8,219
		45,786		8,219
Inventory reserve		(346)		(37)
	$	45,440	$	8,182

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 $19.3 million, $9.7 million and $8.8 million for the years ended December 31, 2011, 2010 and 2009. Major classifications of property, plant and equipment and their respective useful lives are as follows (in thousands):

	Estimated   Useful  Lives	As of December 31,
		2011		2010
Land	Indefinite	$	1,023	$	395
Machinery and equipment	5-10 years		212,674		79,380
Building and leasehold improvements	5-25 years		10,996		5,092
Transportation equipment	5 years		11,438		4,773
Office furniture, fixtures and equipment	5-10 years		2,743		1,005
			238,874		90,645
Less: accumulated depreciation			(46,539)		(27,712)
			192,335		62,933
Assets not yet placed in service			21,362		25,462
Property, plant and equipment, net		$	213,697	$	88,395

-62-

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 the Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”) 350, Intangibles – Goodwill and Other, as amended in September 2011. For the year ended December 31, 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 and 2009, the Company performed the two-step impairment test of its goodwill and concluded that no impairment write-down was necessary.

Intangible assets with indefinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. The tests involve the use of different valuation techniques, including a combination of the income and market approach, to determine the fair value of the intangible assets. Determining the fair value of intangible assets is a matter of judgment and often involves the use of significant estimates and assumptions. If the fair value of the intangible assets is less than the carrying value, an impairment loss is recorded.

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. These intangible assets are therefore, subject to the impairment testing described above. No impairment was recorded for the year ended December 31, 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,
			2011		2010
Trade name		15 years	$	3,675	$	3,675
Customer relationship		8-15 years		19,793		6,591
Non-compete, backlog and patent		11-20 months		3,001		-
IPR&D–Total		Indefinite		854		-
Trade Name–Total		Indefinite		6,247		-
	��
				33,570		10,266
Less: accumulated amortization				(8,151)		(4,498)
Intangible assets, net			$	25,419	$	5,768

Total amortization expense for the years ended December 31, 2011, 2010 and 2009 totaled $3.7 million, $1.1 million and $1.1 million, respectively.

-63-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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

Years Ending December 31,
2012	$	2,953
2013		1,949
2014		1,777
2015		1,125
2016		1,125
Thereafter		9,389
	$	18,318

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, as determined by the discounted cash flow analysis, with the carrying value of the related assets. For the years ended December 31, 2011, 2010 and 2009, 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 $0.7 million, $0.7 million and $0.3 million for the years ended December 31, 2011, 2010 and 2009, respectively. Estimated future amortization expense relating to deferred financing costs is as follows (in thousands):

Years Ending December 31,
2012	$	588
2013		588
2014		588
2015		588
2016		176
Thereafter		-
	$	2,528

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

Hydraulic Fracturing Revenue. The Company enters into arrangements with its customers to provide hydraulic fracturing services, which can be either on a spot market basis or under term

-64-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

contracts. The Company only enters into arrangements with customers for which it believes that collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or numerous 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. With respect to services performed under term contracts, customers are invoiced a monthly mandatory payment based on a specified minimum number of hours of service per month as defined in the contract, whether or not those services are actually utilized, upon the earlier of the passage of time or completion of the job. To the extent customers utilize more than the contracted minimum number of hours of service per month, they are invoiced for such excess at rates defined in the contract upon the completion of each job.

Coiled Tubing and Pressure Pumping Revenue. The Company enters into arrangements to provide coiled tubing and pressure pumping services to only those customers for which it believes that collectability is reasonably assured. These arrangements are typically short-term in nature and each job can last anywhere from a few hours to multiple days. Coiled tubing and pressure pumping 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 on an hourly basis for these services 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. The Company charges fees to its customers based on the amount of chemicals and proppants used in providing these services. In addition, ancillary to coiled tubing and pressure pumping revenue, the Company generates revenue from various fluids and supplies that are necessarily consumed during those processes. The Company does not sell or otherwise charge a fee separate and apart from the services it provides for any of the materials consumed while performing hydraulic fracturing, coiled tubing or pressure pumping services.

Equipment Manufacturing Revenue. The Company enters into arrangements to construct equipment for only those customers for which the Company believes that collectability is reasonably assured. Revenue is recognized and the customer is invoiced upon the completion and delivery of each order to the customer.

Stock-Based Compensation. The Company accounts for stock-based compensation cost based on the grant date fair value by using the Black-Scholes option-pricing model. The Company recognizes stock-based compensation cost on a straight-line basis over the requisite service period. Further information regarding stock-based compensation 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 and long-term debt. The recorded values of

-65-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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 approximates its fair value, as interest approximates market rates.

Income Taxes. Income taxes are provided for the tax effects of transactions reported in financial statements and consist of taxes currently due plus deferred taxes. 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 in income in the period that includes the enactment date. Deferred income tax expense represents the change during the period in the deferred tax assets and deferred tax liabilities.

The components of the deferred tax assets and liabilities are individually classified as current and noncurrent based on their characteristics. Deferred tax assets are reduced by a valuation allowance 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. Effective January 1, 2009, the Company adopted guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the financial statements and applies to all income tax positions. Each income tax position is assessed using a two step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. The Company did not recognize any uncertain tax positions upon adoption of the guidance and had no uncertain tax positions as of December 31, 2011 and 2010. Management believes there are no tax positions taken or expected to be taken in the next twelve months that would significantly change the Company’s unrecognized tax benefits.

The Company will record income tax related interest and penalties, if applicable, 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, 2011, 2010 and 2009. The tax years that remain open to examination by the major taxing jurisdictions to which the Company is subject range from 2007 to 2010. The Company has identified its major taxing jurisdictions as the United States of America and Texas. None of the Company’s federal or state tax returns are currently under examination.

The Company is subject to the Texas Margin Tax, which is determined by applying a tax rate to a base that considers both revenue and expenses. It is considered an income tax and is accounted for in accordance with the provisions of FASB ASC 740,Income Taxes.

-66-

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 ordinary shares outstanding during the applicable period. Diluted earnings per share is computed based on the weighted average number of ordinary shares and ordinary share equivalents outstanding in the applicable period, as if all potentially dilutive securities were converted into ordinary shares (using the treasury stock method).

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,
	2011		2010		2009
	(In thousands, except per share amounts)
Numerator:
Net income (loss) attributed to common shareholders	$	161,979	$	32,272	$	(2,430)
Denominator:
Weighted average common shares outstanding		49,315		46,352		46,323
Effect of potentially dilutive common shares:
Warrants and stock options		1,465		1,499		-
Weighted average common shares outstanding and assumed conversions		50,780		47,851		46,323
Income (loss) per common share:
Basic	$	3.28	$	0.70	$	(0.05)
Diluted	$	3.19	$	0.67	$	(0.05)
Potentially dilutive securities excluded as anti-dilutive		2,344		243		254

Recent Accounting Pronouncements. In December 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-09, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” (“ASU 2010-29”). ASU 2010-29 addresses diversity in the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. If a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The Company adopted ASU 2010-29 on January 1, 2011. This update had no impact on the Company’s consolidated financial statements.

In September 2011, the FASB issued ASU No. 2011-08, “Intangibles — Goodwill and Other” (“ASU 2011-08”). ASU 2011-08 allows a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount before applying the two-step goodwill

-67-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

impairment test. If it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the two-step impairment test for that reporting unit would be performed. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 and early adoption is permitted. The Company elected to early adopt this update for the fiscal year beginning January 1, 2011. The adoption of this update did not have a material impact on the Company’s consolidated financial statements.

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

Note 2 - Long-Term Debt

Long-term debt consisted of the following:

	As of December 31,
	2011		2010
Senior Secured Revolving Credit Facility maturing on April 19, 2016	$	-	$	-
Senior Secured Credit Facility maturing on June 1, 2013		-		47,039
Subordinated Term Loan maturing on June 30, 2014		-		25,000
		-		72,039
Less: amount maturing within one year		-		27,222
	$	-	$	44,817

Senior Secured Revolving Credit Facility

On April 19, 2011, the Company entered into a five-year $200.0 million senior secured revolving credit agreement (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 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 Subsidiaries. The Credit Facility enables the Company to borrow funds on a revolving basis for working capital needs and also provides for the issuance of letters of credit. In addition, the Company may request additional commitments of up to $75.0 million through an incremental facility upon the satisfaction of certain conditions. Up to the entire Credit Facility amount may be drawn as letters of credit, and the Credit Facility has a sublimit of $15.0 million for swing line loans. As of December 31, 2011, no amounts were outstanding under the Credit Facility leaving the entire $200.0 million available for borrowing.

Under the terms of the Credit Facility, outstanding loans bear interest at either LIBOR or a base rate, at the Company’s 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 the Company’s leverage ratio. The

-68-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

leverage ratio is the ratio of funded indebtedness to EBITDA, as defined in the Credit Facility, for the Company and its Subsidiaries on a consolidated basis. 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 its Subsidiaries, as guarantors.

Voluntary prepayments are permitted under the terms of the Credit Facility at any time without penalty or premium.

The Credit Facility provides for payment of certain fees and expenses, including (1) a fee on the revolving loan commitments which varies depending on the Company’s leverage ratio, (2) a letter of credit fee on the stated amount of issued and undrawn letters of credit and a fronting fee to the issuing lender, and (3) other customary fees, including an agency fee.

The Credit Facility contains, among other things, restrictions on the Company’s ability to consolidate or merge with other companies, conduct asset sales, incur additional indebtedness, grant liens, issue guarantees, make investments, loans or advances, pay dividends, enter into certain transactions with affiliates and to make capital expenditures in excess of $100.0 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 from the subsequent fiscal year. In addition, the capital expenditure restrictions do not apply to, among other things, capital expenditures financed solely with proceeds from the issuance of common equity interests or to normal replacement and maintenance capital expenditures.

The Credit Facility contains customary affirmative covenants including financial reporting, governance and notification requirements. The Credit Facility requires the Company to maintain, measured on a consolidated basis, (1) an “Interest Coverage Ratio” of not less than 3.00 to 1.00 and (2) a “Leverage Ratio” of not greater than 3.25 to 1.00, as such terms are defined in the Credit Facility. The Company was in compliance with all debt covenants under the Credit Facility as of December 31, 2011.

The Credit Facility provides that, upon the occurrence of events of default, obligations there under may be accelerated and the lending commitments terminated. Such events of default include, among other things, payment defaults to lenders, failure to meet covenants, material inaccuracies of representations or warranties, cross defaults to other indebtedness, insolvency, bankruptcy, Employee Retirement Income Security Act (“ERISA”) and judgment defaults, and change in control, which includes (1) a change in control under certain unsecured indebtedness issued by the Company or its Subsidiaries, (2) a person or group other than certain permitted holders becoming the beneficial owner of 35% or more of the Company’s voting securities, or (3) the board of directors being comprised for a period of 18 consecutive months of individuals who were neither members at the beginning of such period nor approved by individuals who were members at the beginning of such period.

Each loan and issuance of a letter of credit under the Credit Facility is subject to the conditions that the representations and warranties in the loan documents remain true and correct in all material respects and no default or event of default shall have occurred or be continuing at the time of or immediately after such borrowing or extension of a letter of credit.

-69-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Senior Secured Credit Facility

On May 28, 2010, the Company entered into a senior credit facility with a financial institution maturing on June 1, 2013 with maximum allowable indebtedness of $126.7 million and principal installments of $2.5 million to be paid monthly, with any remaining balance due at maturity. Under the terms of this facility, interest was payable monthly at a variable interest rate determined from a pricing scale based on debt/EBITDA ratio, as defined in the Credit Facility, with a LIBOR floor of 1.5%. This facility was retired on April 19, 2011 with funds received from the Credit Facility used to pay down remaining principal and accrued interest. The Company recognized expense of approximately $2.4 million in remaining deferred financing costs associated with the early extinguishment of this facility as “Loss on early extinguishment of debt” in the consolidated statements of operations. The weighted average interest rate for this facility approximated 5.0% at December 31, 2010.

Subordinated Term Loan

On May 28, 2010, the Company entered into a $25.0 million subordinated term loan with a financial institution maturing on June 30, 2014. Under the term loan, interest was payable monthly at a rate of LIBOR plus 13%, with a LIBOR floor of 1.0%. The term loan was retired on April 19, 2011 using funds received from the Credit Facility to pay down remaining principal and accrued interest. The Company incurred $4.7 million in early termination penalties as a result of the early extinguishment and wrote off approximately $0.5 million in remaining deferred financing costs. These costs were recognized as “Loss on early extinguishment of debt” in the consolidated statements of operations. The interest rate for the term loan was 14.0% at December 31, 2010.

Note 3 - Derivative Liabilities

TheDerivatives and Hedging topic of the FASB Accounting Standards Codification (“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 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 1,176,224 warrants as of the date of loan termination and exercised the warrants in full in December 2010.

-70-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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).

The effect of these derivative instruments on the consolidated statements of operations for the years ended December 31, 2011, 2010 and 2009 was as follows (in thousands):

			Years Ended December 31,
			2011		2010		2009
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	$	336
Total			$	-	$	10,403	$	336

Note 4 - Acquisitions

On April 28, 2011, the Company acquired all of the outstanding common stock of 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

-71-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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.

Note 5 – Income Taxes

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

	Years Ended December 31,
	2011		2010		2009
Current provision:
Federal	$	37,687	$	10,502	$	-
State		4,751		1,540		238
Total current provision		42,438		12,042		238
Deferred (benefit) provision:
Federal		45,039		8,327		(624)
State		864		-		-
Total deferred (benefit) provision		45,903		8,327		(624)
Provision (benefit) for income taxes	$	88,341	$	20,369	$	(386)

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

	Years Ended December 31,
	2011		2010		2009
Federal statutory rate		35.0%		35.0%		34.0%
State taxes, net of federal benefit		2.3%		2.9%		-8.5%
Non-deductible amortization expense on intangibles		0.0%		0.0%		-11.9%
Other		-2.0%		0.8%		0.1%
Effective income tax rate		35.3%		38.7%		13.7%

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

	As of December 31,
	2011		2010
Deferred tax assets - short-term	$	789	$	265
Deferred tax liabilities - long-term		(62,471)		(12,058)
Total	$	(61,682)	$	(11,793)

-72-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

The Company’s deferred tax assets and liabilities as of December 31, 2011 and 2010 consist of the following (in thousands):

	As of December 31,
	2011		2010
Deferred tax assets:
Compensation	$	4,530	$	655
Amortization of goodwill and intangible assets		3,586		-
Allowance for doubtful accounts		289		178
Inventory reserves		121		13
Section 263a “Unicap”		181		-
Accruals		362		73
Total gross deferred tax assets		9,069		919
Valuation allowance		-		-
Total gross deferred tax assets		9,069		919
Deferred tax liabilities:
Depreciation on property, plant and equipment		(59,521)		(9,429)
Amortization of goodwill		(11,230)		(3,283)
Total gross deferred tax liabilities		(70,751)		(12,712)
Net deferred tax liability	$	(61,682)	$	(11,793)

Note 6 - Stock-Based Compensation

Prior to December 23, 2010, all options granted to the Company’s employees were granted under the C&J Energy Services, Inc. 2006 Stock Option Plan (the “2006 Plan”). The 2006 Plan provided for awards of incentive stock options, non-statutory stock options, restricted stock, and other stock based awards to employees, officers, directors, consultants and advisors. Only non-qualified stock options were awarded under the 2006 Plan. Options awarded under the 2006 Plan generally vested 20% on grant date and another 20% on each of the first four anniversaries of the grant date. However, two employees were given fully vested options on the grant date. The options expire on the tenth anniversary of the date of grant. On December 23, 2010, the 2006 Plan was amended to provide, among other things, that (1) no additional awards would be granted under the 2006 Plan, (2) all awards outstanding under the 2006 Plan would continue to be subject to the terms of the 2006 Plan, and (3) all unvested options under the 2006 Plan would immediately vest and become exercisable in connection with the completion of a private placement of the Company’s common stock that occurred in December 2010.

On December 23, 2010, the Company adopted the C&J Energy Services, Inc. 2010 Stock Option Plan (the “2010 Plan”). The Company’s 2010 Plan permits the grant of non-statutory stock options and incentive stock options to its employees, consultants and outside directors for up to 5,699,889 shares of common stock. Under the 2010 Plan, option awards are generally granted with an

-73-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on comparable public company data. The Company makes estimates with respect to employee termination and forfeiture rates of the options within the valuation model. The expected term of options granted is derived using the “plain vanilla” method due to the lack of history and volume of option activity at the Company. 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, 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 December 31,
	2011	2010
Expected volatility	75.0%	75.0%
Expected dividends	None	None
Exercise price	$10 - $29	$10
Expected term (in years)	5 - 6	6
Risk-free rate	1.1% - 2.6%	2.1%

The weighted average grant date fair value of options granted during the years ended December 31, 2011 and 2010 was $15.30 and $6.64, respectively. There were no options granted during the year ended December 31, 2009.

As of December 31, 2011, the Company had 6,797,089 options outstanding to employees and nonemployee directors, 1,819,818 of which were issued under the 2006 Plan and the remaining 4,977,271 were issued under the 2010 Plan. As of December 31, 2011 there were 722,618 shares available for issuance under the 2010 Plan.

-74-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

A summary of option activity under the plans for the year ended December 31, 2011 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, 2011		5,232		$	6.93
Granted		1,654			23.11
Exercised		(87	)		1.43
Forfeited		(2	)		11.00
Outstanding at December 31, 2011		6,797		$	10.94		8.09	$	76,623
Exercisable at December 31, 2011		2,946		$	4.81		6.66	$	47,485

The total intrinsic value of options exercised during the year ended December 31, 2011 was $1.5 million. No options were exercised prior to 2011. As of December 31, 2011, there was $31.3 million of total unrecognized compensation cost related to outstanding stock options. That cost is expected to be recognized over a weighted-average period of 2.26 years.

Stock-based compensation expense was $10.8 million, $0.6 million and $0.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. The total income tax benefit recognized in the statement of operations in connection with stock-based compensation expense was approximately $3.9 million, $0.2 million and $45,000 for the years ended December 31, 2011, 2010 and 2009, 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 years ended December 31, 2010 and 2009, purchases from Total were $26.4 million, $22.2 million and $1.5 million, respectively. Deposits on equipment to be purchased at December 31, 2010 totaled $4.2 million and amounts payable at December 31, 2010 totaled $73,783.

The Company obtains trucking and crane services on an arm’s length basis from certain vendors affiliated with one of its executive officers. For the years ended December 31, 2011, 2010 and 2009, purchases from these vendors totaled $5.7 million, $0.2 million and $46,800, respectively. Amounts payable to these vendors at December 31, 2011 and 2010 were $0.8 million and $0, respectively.

-75-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

The Company purchases certain of its equipment on an arm’s length basis from vendors affiliated with a member of its Board of Directors. For the years ended December 31, 2011, 2010 and 2009, purchases from these vendors were $8.1 million, $0.8 million and $0, respectively. Amounts payable to these vendors at December 31, 2011 and 2010 were $0.7 million and $0.1 million, respectively.

Note 8 – Business Concentrations

Concentration of Credit Risk

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

The Company’s top ten customers accounted for approximately 92.7 %, 90.2% and 90.6% of revenues for the years ended December 31, 2011, 2010 and 2009, respectively. 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. In 2009, sales to Penn Virginia, Anadarko Petroleum and EnCana represented 25.9%, 11.7% and 11.0%, respectively, of the Company’s total sales. Revenue is earned from each of these customers within the Company’s Stimulation and Well Intervention Services segment.

Supplier Concentrations

The Company purchases materials and equipment from a limited number of suppliers. In general, management believes it will be able to make satisfactory alternative arrangements in the event of interruption of supply. Should any of the current suppliers be unable to provide the necessary raw materials (such as proppant, guar, chemicals or coiled tubing), finished products (such as fluid-handling equipment) or 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 the business, financial condition, results of operations and cash flows. During the year ended December 31, 2011, the Company purchased 5% or more of materials or equipment from each of Economy Polymers & Chemicals and Total. During the year ended December 31, 2010, the Company purchased 5% or more of materials or equipment from each of Economy Polymers & Chemicals, Total, Weir SPM and Sintex Minerals & Services, Inc.

Note 9 – Commitments and Contingencies

Hydraulic Fracturing Term Contracts

The Company has entered into certain take-or-pay contracts for the provision of hydraulic fracturing services that guarantee a minimum level of monthly revenue. The revenue related to these contracts is recognized on the earlier of the passage of time under terms as defined by the respective contract or as the services are performed.

-76-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Supplier Agreements

The Company has non-cancelable purchase agreements with suppliers of goods and services. The terms of these contracts range from 12 to 36 months and have various minimum purchase requirements. As of December 31, 2011, the minimum purchase obligations under these supplier agreements were $26.3 million, $15.2 million and $15.2 million for 2012, 2013, and 2014, 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 with varying payment dates throughout each month.

-77-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

Lease expense under operating leases totaled $5.5 million, $2.9 million and $0.7 million for the years ended December 31, 2011, 2010 and 2009, respectively. As of December 31, 2011, the future minimum lease payments under non-cancelable operating leases were as follows (in thousands):

Years Ending December 31,
2012	$	5,547
2013		5,438
2014		3,493
2015		769
2016		668
Thereafter		50
	$	15,965

Note 10 – Employee Benefit Plan

The Company maintains a contributory profit sharing plan under a 401(k) arrangement which covers all employees meeting certain eligibility requirements. Eligible employees can make annual contributions to the plan 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, 2011, 2010 and 2009 totaled $0.2 million, $0.2 million and $0.1 million, respectively.

Note 11 – Segment Information

In accordance with FASB ASC Topic 280,Segment Reporting, the Company routinely evaluates whether or not it has separate operating and reportable segments. Prior to April 2011, the Company determined that it had one operating segment with three related service lines: hydraulic fracturing, coiled tubing and pressure pumping. In reaching this conclusion, management considered the following: (1) the Company’s chief operating decision maker (“CODM”) evaluates performance and makes resource allocation decisions as a single business as opposed to based on discrete service lines, (2) the Company’s business relies on a single infrastructure and uses one labor force that is available to all service lines provided, (3) the Company’s marketing efforts focus on promoting an integrated service package rather than distinct service offerings to discrete customers and (4) the Company’s compensation policy is determined with respect to overall performance rather than the performance of individual services. Each of these factors contributed to management’s conclusion that the Company operated as a single segment prior to April 2011.

During the second quarter of 2011, the Company reevaluated whether or not it had more than one operating segment and concluded that, with the acquisition of Total in April 2011, two operating and reportable segments exist: Stimulation and Well Intervention Services and Equipment Manufacturing. This determination was made based on the following factors: (1) the Company’s CODM is currently managing these two segments as separate businesses, evaluating performance and making resource allocation decisions distinctly, and expects to do so for the foreseeable future, and

-78-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(2) discrete financial information for each segment is available. The following is a brief description of these segments:

Stimulation and Well Intervention Services. This business segment has three related service lines providing hydraulic fracturing, coiled tubing and pressure pumping services, with a focus on complex, technically demanding well completions.

Equipment Manufacturing. This business segment constructs equipment, conducts equipment repair services and provides oilfield parts and supplies for the Company’s Stimulation and Well Intervention Services segment as well as for third-party customers in the energy services industry.

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 years ended December 31, 2010 and 2009 has not been presented because, as previously mentioned, the Company did not have separate operating segments prior to the acquisition of Total.

	Stimulation and Well Intervention Services		Equipment Manufacturing		Corporate and Other			Total
	(in thousands)
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		(38,241	)		285,040
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
Identifiable 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 business segment for the years ended December 31, 2011, 2010 and 2009 are as follows (in thousands):

	Years Ended December 31,
Service Line	2011		2010		2009
Hydraulic fracturing	$	619,772	$	182,657	$	38,105
Coiled tubing		97,187		50,592		23,349
Pressure pumping		19,432		10,908		5,576
Total revenue	$	736,391	$	244,157	$	67,030

-79-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

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

As required under 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).

	Year Ended December 31, 2011
Adjusted EBITDA	$	285,040
Interest expense, net		(4,221	)
Loss on early extinguishment of debt		(7,605	)
Provision for income taxes		(88,341	)
Depreciation and amortization		(22,919	)
Gain (loss) on disposal of assets		25
Net income	$	161,979

Note 12 – Initial Public Offering

On July 28, 2011, the Company’s registration statement on Form S-1 (Registration Statement No. 333-173177) relating to its initial public offering (the “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.

The Company registered an additional 38,463,074 shares of common stock on a shelf registration statement on Form S-1 (Registration Statement 333-173188), which was declared effective

-80-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

by the SEC on September 30, 2011. This registration statement provides for the offering and sale of shares of the Company’s common stock held by the selling stockholders named therein in full satisfaction of the registration rights agreement entered into in connection with the Company’s private placement of common stock in December 2010. The selling stockholders will receive all of the proceeds from the sale of these shares of common stock if and when sold.

Note 13 – Quarterly Financial Data (unaudited)

Summarized quarterly financial data for the years ended December 31, 2011 and 2010 are presented below (in thousands, except per share amounts).

	Quarters Ended
	March 2011		June 2011		September 2011		December 2011
Revenue	$	127,205	$	182,171	$	229,027	$	220,051
Gross profit		57,157		72,103		90,195		95,443
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

	Quarters Ended
	March 2010		June 2010		September 2010		December 2010
Revenue	$	32,637	$	41,803	$	83,921	$	85,796
Gross profit		9,461		14,685		31,343		34,371
Operating income		6,610		9,239		26,674		27,768
Income before income taxes		3,659		2,655		22,727		23,600
Net income		2,243		1,717		13,810		14,502
Net income per common share
-Basic	$	0.05	$	0.04	$	0.30	$	0.31
-Diluted	$	0.05	$	0.04	$	0.29	$	0.30

-81-

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Our financial statements for the years ended December 31, 2008 and 2009 were audited by Flackman Goodman & Potter, P.A., or “Flackman,” an independent public accounting firm. At the time that Flackman performed audit services for us, we were not a public company and were not subject to SEC regulations, including the requirement for our auditors to be a Public Company Accounting Oversight Board (“PCAOB”) registered accounting firm. In preparation for our IPO, on December 17, 2010, we dismissed Flackman and engaged UHY LLP, “UHY,” an independent PCAOB registered public accounting firm, to audit our financial statements as of and for the year ended December 31, 2010 and to re-audit our financial statements as of December 31, 2009 and for the years ended December 31, 2008 and 2009. These financial statements, including UHY’s audit report thereon, are included in this Form 10-K. The engagement of UHY was approved by our Board of Directors.

Neither of Flackman’s reports on the financial statements for the years ended December 31, 2008 and 2009 contained an adverse opinion or disclaimer of opinion, or was qualified or modified as to uncertainty, audit scope, or accounting principles. During such time period, there were no disagreements between us and Flackman on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure.

We have provided Flackman with a copy of the disclosure contained in this Form 10-K, which was received by Flackman on February 21, 2012. Flackman has furnished a letter addressed to the SEC and filed as an exhibit to this Form 10-K stating its agreement with the statements made in this Form 10-K. A copy of the Flackman letter has been filed as an exhibit to this Form 10-K.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our 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) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our 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, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2011 at the reasonable assurance level.

Management’s Report Regarding Internal Control. This annual report does not include a report of Management’s assessment regarding internal control over financial reporting or an attestation report of the Company’s independent registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies. We will be required to include our internal management assessment and an attestation report from our independent registered public accounting firm in our December 31, 2012 annual report filed with the SEC in 2013 regarding the effectiveness of our internal control over financial reporting.

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, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

-82-

Item 9B. Other Information

None.

-83-

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers and Directors

Set forth below are the names, ages and positions of our executive officers and directors as of February 24, 2012. All directors are elected for a term of one year and serve until their successors are elected and qualified or upon earlier of death, resignation or removal. All executive officers hold office until their successors are elected and qualified or upon earlier of death, resignation or removal.

Name	Age		Position with Our Company
Joshua E. Comstock		42	President, Chief Executive Officer and Chairman of the Board of Directors
Randall C. McMullen, Jr.		36	Executive Vice President, Chief Financial Officer, Treasurer and Director
Bretton W. Barrier		45	Chief Operating Officer
Theodore R. Moore		34	Vice President — General Counsel and Corporate Secretary
Brandon D. Simmons		43	Vice President — Coiled Tubing
John D. Foret		48	Vice President — Coiled Tubing
William D. Driver		45	Vice President — Hydraulic Fracturing
J. P. “Pat” Winstead		54	Vice President — Sales and Marketing
Darren M. Friedman		43	Director
James P. Benson		52	Director
Michael Roemer		53	Director
H. H. “Tripp” Wommack, III		56	Director
C. James Stewart, III		63	Director

Joshua E. Comstock — Mr. Comstock has served as our Chief Executive Officer and as one of our directors since 1997. Mr. Comstock was given the additional title of President in December 2010 and the title of Chairman of the Board in February 2011. In 1997, Mr. Comstock was a founder of C&J. Mr. Comstock is responsible for general oversight of our company. Mr. Comstock began working as a foreman on several specialized natural gas pipeline construction projects. Through this experience, Mr. Comstock gained extensive knowledge and understanding of the gathering and transporting of natural gas. In January 1990, Mr. Comstock began working for J4 Oilfield Service, a test pump services company. His primary responsibility was working in natural gas production as a service contractor for Exxon.

As a founder of our company, Mr. Comstock is one of the driving forces behind us and our success to date. Over the course of our history, Mr. Comstock has successfully grown us through his leadership skills and business judgment and for this reason we believe Mr. Comstock is a valuable asset to our Board and is the appropriate person to serve as Chairman of the Board.

Randall C. McMullen, Jr. — Mr. McMullen has served as our Executive Vice President, Chief Financial Officer and Treasurer and director since joining us in August 2005. Prior to joining our company, Mr. McMullen held various positions with Credit Suisse First Boston, the GulfStar Group and Growth Capital Partners. Mr. McMullen graduated magna cum laude from Texas A&M University with a B.B.A. in Finance.

-84-

During Mr. McMullen’s tenure with us, we have grown rapidly. Mr. McMullen’s financial and investment banking expertise have been invaluable to us in our efforts to continue our growth through raising additional capital, and he is also extensively involved in our operations. For this reason, we believe Mr. McMullen is well suited to serve on our Board of Directors.

Bretton W. Barrier — Mr. Barrier has served in multiple positions since joining us in January 2007, including Vice President — Hydraulic Fracturing, and, most recently, Chief Operating Officer. Mr. Barrier has over 20 years of experience in the oil and gas industry. He is responsible for all of our Fracturing Operations, including management of teams at each operating location, customer and vendor management and health and safety matters. Prior to joining us, Mr. Barrier worked for El Paso/Coastal from July 2000 to January 2007, where he oversaw production, completions and workovers for all South Texas operations, as well as supervised over 60% of that division’s fracturing treatments from 2003 to 2007. Prior to working at El Paso/Coastal, Mr. Barrier worked for Halliburton from August 1990 to July 2000, where he served in various positions including equipment operator, service supervisor and service leader.

Theodore R. Moore — Mr. Moore has served as our Vice President — General Counsel and Corporate Secretary since February 2011. Prior to that time, Mr. Moore practiced corporate law at Vinson & Elkins L.L.P. from 2002 through January 2011. Mr. Moore represented public and private companies and investment banking firms in numerous capital markets offerings and mergers and acquisitions, primarily in the oil and gas industry. Mr. Moore received a B.A. in Political Economy from Tulane University and a J.D. from Tulane Law School.

Brandon D. Simmons — Mr. Simmons has been with our company since 2001, primarily as an operational manager of our coiled tubing unit. Mr. Simmons has served as our Vice President — Coiled Tubing since 2005. Mr. Simmons operated the first Stewart & Stevenson coiled tubing unit ever built and has a complete mechanical knowledge of coiled tubing units and supporting equipment. Mr. Simmons has been heavily involved in the design of our coiled tubing units. Prior to joining our company, Mr. Simmons spent eight years with Superior Energy and Preeminent Coiled Tubing Services operating coiled tubing units.

John D. Foret — Mr. Foret has been with our company since 2001. Mr. Foret has served as our Vice President — Coiled Tubing since 2008. Mr. Foret has 25 years of experience in the oil and gas industry and currently is responsible for our coiled tubing operations. Prior to joining us, Mr. Foret was a workover supervisor for Cudd Energy Services, covering various geographical areas, including the Southern United States, Gulf of Mexico, Norway and Scotland. Additionally, through his employment with Hydraulic Well Control, Mr. Foret worked in Norway and Scotland while providing services to ConocoPhillips, Exxon Mobil, StatOil and Shell, as well as in India and Venezuela.

William D. Driver — Mr. Driver has served as our Vice President — Hydraulic Fracturing since joining us in August 2007. Mr. Driver has 20 years of experience in the oil and gas industry. Along with Mr. Barrier, he is responsible for our company’s Fracturing Operations. Prior to joining our company, Mr. Driver worked for Halliburton in the capacity of equipment operator, service supervisor, field service quality coordinator, operations manager and camp manager from August 1990 to August 2007.

J.P. “Pat” Winstead — Mr. Winstead has served as our Vice President — Sales and Marketing since 2008, having joined us in 2005 as a corporate sales representative. Mr. Winstead’s primary role at our company is to oversee our sales and marketing efforts. Mr. Winstead also managed and will continue to manage our expansion into new regions, specifically East Texas/North Louisiana and

-85-

Western Oklahoma. Prior to joining our company, Mr. Winstead spent the last 25 years working in various sales and marketing roles for several companies, including Sundance Cattle Co. and Sundance Services, Inc.

Darren M. Friedman — Mr. Friedman has served as one of our directors since December 2010. Mr. Friedman is a Partner of StepStone Group LLC, focusing on private equity partnership, equity and mezzanine investments. Prior to joining StepStone in 2010, Mr. Friedman was a Managing Partner of Citi Private Equity from 2001 to 2010, managing over $10 billion of capital across three private equity investing activities. Mr. Friedman sits or has sat on the boards or advisory boards of several portfolio companies, funds and a number of Investment Committees. Mr. Friedman currently serves on the boards of ServiceMaster Global Holdings, Educate Inc., Educate Online Inc. and Laureate Education, Inc. Prior to joining Citi Private Equity, Mr. Friedman worked in the Investment Banking division at Salomon Smith Barney. Mr. Friedman received an M.B.A. from the Wharton School at the University of Pennsylvania and a B.S. in Finance from the University of Illinois.

Mr. Friedman brings extensive business, financial and banking expertise to our Board of Directors from his background in investment banking and private equity fund management. Mr. Friedman also brings extensive prior board service experience to our Board from his service on numerous other boards/limited partnership advisory boards.

James P. Benson — Mr. Benson has served as one of our directors since December 2010. Mr. Benson is a founding shareholder and a Managing Partner of Energy Spectrum, which manages private equity through institutional partnerships styled as Energy Spectrum Partners and Energy Trust Partners, and also manages a Financial Advisory business focused on energy mergers and acquisitions and institutional financings named Energy Spectrum Advisors, Inc. Energy Spectrum was established in 1996. Prior to Energy Spectrum, Mr. Benson was a Managing Director of Reid Investments, Inc., a private investment banking firm focused on energy mergers and acquisitions and financial advisory services, joining the firm in mid-1987. He started his career at InterFirst Bank Dallas, and was a credit officer focused on energy lending and energy work-out. Mr. Benson currently serves on the board of several privately held companies related to Energy Spectrum. Mr. Benson graduated from the University of Kansas with a B.S. in Finance and earned his M.B.A. with a concentration in Finance from Texas Christian University.

Mr. Benson’s extensive financial and banking experience in the energy industry from his over 20 years of experience working at private equity firms specializing in the energy industry make him well qualified to serve on our Board.

Michael Roemer — Mr. Roemer has served as one of our directors since December 2010. Mr. Roemer previously served as the Chief Financial Officer of Hammond, Kennedy, Whitney & Co. (“HKW”), a private equity group, and as a partner in several affiliate funds of HKW from 2000 until January 1, 2012. Upon his retirement from HKW, Mr. Roemer founded Roemer Financial Consulting, where he is presently employed. Prior to joining HKW, Mr. Roemer served as a Shareholder and Vice President of Flackman, Goodman & Potter, P.A., a certified public accounting firm, from 1988 to 2000. Mr. Roemer is a licensed CPA with over 30 years experience, and is a member of the American Institute of Certified Public Accountants and the New Jersey Society of Certified Public Accountants. Mr. Roemer received his B.S. in Accounting from the University of Rhode Island.

Mr. Roemer’s extensive background in public accounting combined with his subsequent experience as the chief financial officer of a private equity firm and his experience as a licensed CPA make him well qualified to serve on our Board.

-86-

H.H. Wommack, III — Mr. Wommack has served as one of our directors since December 2010. Mr. Wommack is currently the Chairman, President and CEO of Saber Oil and Gas Ventures, LLC, an oil and gas company that focuses on acquisition and exploitation efforts in the Permian Basin of West Texas and Southeast New Mexico. Mr. Wommack has served in this position since August 2008. Mr. Wommack also serves as the Chairman of Cibolo Creek Partners, LLC, which specializes in commercial real estate investments, and Globe Energy Services, LLC, an energy services company in the Permian Basin. Prior to his current positions, Mr. Wommack was Chairman, President and CEO of Southwest Royalties, Inc. from August 1983 to August 2004 and Saber Resources from July 2004 until August 2008. Additionally, Mr. Wommack was the Founder, Chairman and CEO of Basic Energy Services (formerly Sierra Well Services, Inc.), and following its initial public offering, Mr. Wommack continued to serve on the board of Basic Energy Services through June 2009. Mr. Wommack graduated with a B.A. from the University of North Carolina, Chappell Hill, and earned a J.D. from the University of Texas.

Mr. Wommack adds extensive executive and management expertise to us from his background as chairman and/or chief executive officer of numerous companies. In addition, we believe Mr. Wommack’s knowledge from serving as chairman and chief executive officer of a company that went through an initial public offering will be valuable to us in our registration process. For these reasons, we believe Mr. Wommack to be an asset to our Board.

C. James Stewart III — Mr. Stewart has served as one of our directors since December 2010. Since 2003 Mr. Stewart has served as the Chairman of Stewart & Sons Holding Co., which he wholly owns. He also serves as Chairman of Supreme Electrical Services, Inc. and Lime Instruments, each of which Stewart & Sons Holding Co. has a 50% ownership interest, and Surefire Industries, USA, of which Surefire has a 50% ownership interest. From 1972 to 2003, Mr. Stewart worked at Stewart & Stevenson in multiple capacities, including serving as Executive Vice President and Director from 1999 to 2003. Mr. Stewart received a B.S. from Texas Christian University.

We believe Mr. Stewart’s extensive business and marketing experience at a large oil field services company make him a valuable member of our Board of Directors.

There are no family relationships among any of our directors or executive officers.

Section 16(a) Beneficial Ownership Reporting Compliance

Under Section 16(a) of the Exchange Act, directors, officers and beneficial owners of 10 percent or more of our common stock (“Reporting Persons”) are required to report to the SEC on a timely basis the initiation of their status as a Reporting Person and any changes with respect to their beneficial ownership of our common units. Based solely on a review of Forms 3, 4 and 5 (and any amendments thereto) furnished to us, we have concluded that no Reporting Persons were delinquent with respect to their reporting obligations, as set forth in Section 16(a) of the Exchange Act.

Stockholder Board Nominations

On February 27, 2012, our Board adopted the Second Amended and Restated Bylaws (“bylaws”), which clarify the procedures by which stockholders may recommend nominees to our Board. Pursuant to Section 2.06 of the bylaws, stockholders who wish to recommend a nominee to our Board must have given timely notice thereof in writing to our Secretary. To be timely, a stockholder’s notice shall be delivered to our Secretary at our principal executive offices not later than

-87-

the close of business on the 90th day, nor earlier than the close of business on the 120th day, prior to the first anniversary of the preceding year’s annual meeting (provided, however, that in the event that the date of the annual meeting is more than thirty (30) days before or more than seventy (70) days after such anniversary date, notice by the stockholder must be so delivered not earlier than the close of business on the 120th day prior to such annual meeting and not later than the close of business on the later of the 90th day prior to such annual meeting or the 10th day following the day on which public announcement of the date of such meeting is first made by the Corporation; provided, further, however, that in the event there was no proceeding year’s annual meeting, notice by the stockholder must be so delivered not later than the 10th day following the day on which public announcement of the date of such meeting is first made by the Corporation).

Information About our Board of Directors

Our Board of Directors is comprised of the following seven members: Joshua E. Comstock, as Chairman of the Board; Randall C. McMullen, Jr.; Darren Friedman; James P. Benson; Michael Roemer; H. H. “Tripp” Wommack, III and C. James Stewart, III. Messrs. Benson and Friedman were appointed pursuant to the Amended and Restated Stockholders’ Agreement. Please read Part III, Item 13 “Certain Relationships and Related Party Transactions, and Director Independence — Amended and Restated Stockholders’ Agreement.” Under the terms of the Amended and Restated Stockholders’ Agreement, subject to retaining certain ownership thresholds, Energy Spectrum was entitled to appoint one director and Citigroup/Stepstone was entitled to appoint one director. Energy Spectrum appointed Mr. Benson and Citigroup/Stepstone appointed Mr. Friedman. Due to the decrease in each of Energy Spectrum and Citigroup/StepStone’s ownership percentages, neither is entitled to appoint a director at this time.

Board Diversity.  The Board seeks independent directors who represent a mix of backgrounds and experiences that will enhance the quality of the Board’s deliberations and decisions. In evaluating directors, we consider diversity in its broadest sense, including persons diverse in perspectives, personal and professional experiences, geography, gender, race and ethnicity. This process has resulted in a Board that is comprised of highly qualified directors that reflect diversity as we define it.

Board Independence.  As a public company, we are required to comply with the corporate governance rules of the NYSE and are subject to the Sarbanes-Oxley Act of 2002 and related SEC rules, (collectively, “Sarbanes-Oxley”). Our Board of Directors has affirmatively determined that no member of our Board, other than Mr. Comstock, Mr. McMullen and Mr. Stewart, has a material relationship with us and, therefore, the remaining members of our Board are “independent” as defined under the NYSE’s listing standards. Please read Part III, Item 13 “Certain Relationships and Related Party Transactions, and Director Independence — Supplier Agreements” for additional information regarding Mr. Stewart’s relationship with one of our suppliers.

Executive Sessions of Our Board of Directors.  The non-management directors of our Board have regularly scheduled meetings in executive session. In addition, because our non-management directors include a director who is not independent under the NYSE’s listing standards, Mr. Stewart, we hold at least one executive session meeting a year of only independent directors. The Board annually chooses a director (the “Lead Director”) to preside over its executive sessions. The Lead Director is responsible for preparing an agenda and for meeting with the independent directors in executive session. On February 27, 2012, Messrs. Benson and Friedman were appointed as our Lead Directors.

-88-

Risk Oversight.  The Board is actively involved in oversight of risks that could affect us. This oversight function is conducted primarily through committees of our Board, as disclosed in the descriptions of each of the committees below and in the charters of each of the committees, but the full Board retains responsibility for general oversight of risks. Our Audit Committee is charged with oversight of our system of internal controls and risks relating to financial reporting, legal, regulatory and accounting compliance. Our Board will continue to satisfy its oversight responsibility through full reports from our Audit Committee chair regarding the committee’s considerations and actions, as well as through regular reports directly from officers responsible for oversight of particular risks within our company. In addition, we have internal audit systems in place to review adherence to policies and procedures, which are supported by a separate internal audit department.

Committees of the Board

Our Board has established three standing committees to assist it in discharging its responsibilities: an Audit Committee, a Compensation Committee and a Nominating and Governance Committee. The following chart reflects the current membership of each committee:

Name	Audit Committee	Compensation Committee	Nominating and Governance Committee
Joshua E. Comstock
Randall C. McMullen, Jr.
Darren M. Friedman	*	*	*
James P. Benson		*	**
Michael Roemer	**	*	*
H. H. “Tripp” Wommack, III	*	**	*
C. James Stewart, III

* Member

** Chairman

Each of these committees has a charter, which we make available on our website at www.cjenergy.com and stockholders may obtain printed copies, free of charge, by sending a written request to C&J Energy Services, Inc., 10375 Richmond Avenue, Suite 2000, Houston, Texas 77042, Attn: Corporate Secretary.

Audit Committee.  Our Audit Committee is responsible for oversight of our risks relating to accounting matters, financial reporting and legal and regulatory compliance. In particular, our Audit Committee has the following purposes pursuant to its charter:

• oversee the quality, integrity and reliability of the financial statements and other financial information we provide to any governmental body or the public;

• oversee our compliance with legal and regulatory requirements;

• retain our independent registered public accounting firm;

• oversee the qualifications, performance and independence of our independent registered public accounting firm;

-89-

• oversee the performance of our internal audit function;

• oversee our systems of internal controls regarding finance, accounting, legal compliance and ethics that our management and Board have established;

• provide an open avenue of communication among our independent registered public accounting firm, financial and senior management, and our Board, always emphasizing that the independent registered public accounting firm is accountable to our Audit Committee; and

• perform such other functions as our Board may assign to our Audit Committee from time to time.

In connection with these purposes and to satisfy its oversight responsibilities, our Audit Committee annually selects, engages and evaluates the performance and ongoing qualifications of, and determines the compensation for, our independent registered public accounting firm, reviews our annual and quarterly financial statements, and confirms the independence of our independent registered public accounting firm. Our Audit Committee meets with our management and independent registered public accounting firm regarding the adequacy of our financial controls and our compliance with legal, tax and regulatory matters and our significant policies. In particular, our Audit Committee separately meets regularly with our chief financial officer, corporate controller, our independent registered public accounting firm and other members of management. Our Audit Committee chair routinely meets between formal committee meetings with our chief financial officer, corporate controller, and our independent registered public accounting firm. The committee also receives regular reports regarding issues such as the status and findings of audits being conducted by the internal and independent auditors, accounting changes that could affect our financial statements and proposed audit adjustments.

While our Audit Committee has the responsibilities and powers set forth in its charter, it is not the duty of our Audit Committee to plan or conduct audits, to determine that our financial statements are complete and accurate, or to determine that such statements are in accordance with U.S. GAAP and other applicable rules and regulations. Our management is responsible for the preparation of our financial statements in accordance with accounting principles generally accepted in the United States and our internal controls. Our independent registered public accounting firm is responsible for the audit work on our financial statements. It is also not the duty of our Audit Committee to conduct investigations or to assure compliance with laws and regulations and our policies and procedures. Our management is responsible for compliance with laws and regulations and compliance with our policies and procedures.

During 2011, our Audit Committee, then, and currently consisting of Mr. Roemer (Chairman), Mr. Friedman and Mr. Wommack, met six times. Subject to a one-year phase-in period, Sarbanes-Oxley and the listing standards of the NYSE require an audit committee consisting of at least three members, each of whom must meet certain independence standards. Our Board has determined that all members of our Audit Committee are independent as that term is defined in the NYSE’s listing standards and by Rule 10A-3 promulgated under the Securities Exchange Act of 1934, as amended, or the Exchange Act. Our Board has determined that each member of our Audit Committee is financially literate and that Mr. Roemer has the necessary accounting and financial expertise to serve as Chairman. Our Board has also determined that Mr. Roemer is an “audit committee financial expert” following a determination that Mr. Roemer met the criteria for such designation under the SEC’s rules and regulations.

-90-

Compensation Committee.  Our Compensation Committee is responsible for risks relating to employment policies and our compensation and benefits systems. Pursuant to its charter, the purposes of our Compensation Committee are to:

• review, evaluate, and approve our agreements, plans, policies, and programs to compensate our corporate officers;

• review and discuss with our management the Compensation Discussion and Analysis to be included in our proxy statement for the annual meeting of stockholders and to determine whether to recommend to our Board that the Compensation Discussion and Analysis be included in the proxy statement, in accordance with applicable rules and regulations;

• produce our Compensation Committee Report for inclusion in the proxy statement, in accordance with applicable rules and regulations;

• otherwise discharge our Boards’ responsibility relating to compensation of our corporate officers; and

• perform such other functions as our Board may assign to our Compensation Committee from time to time

In connection with these purposes, our Board has delegated to our Compensation Committee the overall responsibility for establishing, implementing and monitoring the compensation for our corporate officers. Our Compensation Committee was established in February 2011. The Compensation Committee reviews and approves the compensation of our corporate officers and makes appropriate adjustments based on our performance, achievement of predetermined goals and changes in an officer’s duties and responsibilities. Our Compensation Committee also approves all employment agreements related to the executive team and approves recommendations regarding equity awards for all employees. Together with management, and any counsel or other advisors deemed appropriate by our Compensation Committee, our Compensation Committee reviews and discusses the particular executive compensation matter presented and make a final determination, with the exception of compensation matters relating to our Chief Executive Officer. In the case of our Chief Executive Officer, our Compensation Committee will review and discuss the particular compensation matter (together with our management and any counsel or other advisors deemed appropriate) and formulate a recommendation. Our Compensation Committee’s chairman then reports our Compensation Committee’s recommendation for approval by the full Board or, in certain cases, by the independent directors.

Under its charter, our Compensation Committee has the sole authority to retain and terminate any compensation consultant to be used to assist in the evaluation of the compensation of our corporate officers and directors and also has the sole authority to approve the consultant’s fees and other retention terms.

All of the current members of our Compensation Committee are independent as that term is defined in the NYSE’s listing standards. During 2011, our Compensation Committee, then consisting of Mr. Wommack (Chairman), Mr. Friedman, Mr. Benson, Mr. Stewart and Mr. Roemer, held three meetings. In order to ensure that our Compensation Committee is fully independent by July 28, 2012, the one year anniversary of the effectiveness of our IPO Registration Statement, on February 27, 2012 Mr. Stewart was removed from our Compensation Committee and the Committee’s size reduced to four members.

Nominating and Governance Committee.  Our Nominating and Governance Committee is responsible for oversight relating to management and Board succession planning, and stockholder

-91-

responses to our ethics and business practices. Pursuant to its charter, the purposes of our Nominating and Governance Committee are to:

• assist our Board by identifying individuals qualified to become members of our Board and recommend director nominees to our Board for election at the annual meetings of stockholders or for appointment to fill vacancies;

• recommend director nominees to our Board for each of its committees;

• advise our Board about the appropriate composition of our Board and its committees;

• advise our Board about and recommend to our Board appropriate corporate governance practices and assist our Board in implementing those practices;

• lead our Board in its annual review of the performance of our Board and its committees;

• direct all matters relating to the succession of our Chief Executive Officer;

• review and make recommendations to our Board with respect to the form and amount of director compensation; and

• perform such other functions as our Board may assign to our Nominating and Governance Committee from time to time.

In connection with these purposes, our Nominating and Governance Committee actively seeks individuals qualified to become members of our Board, seeks to implement the independence standards required by law, applicable listing standards, our certificate of incorporation and our bylaws, and identifies the qualities and characteristics necessary for an effective Chief Executive Officer.

Our Nominating and Governance Committee is responsible for establishing criteria for selecting new directors and actively seeking individuals to become directors for recommendation to our Board. In considering candidates for our Board, our Nominating and Governance Committee considers the entirety of each candidate’s credentials. There is currently no set of specific minimum qualifications that must be met by a nominee recommended by our Nominating and Governance Committee, as different factors may assume greater or lesser significance at particular times and the needs of our Board may vary in light of its composition and our Nominating and Governance Committee’s perceptions about future issues and needs. However, while our Nominating and Governance Committee does not maintain a formal list of qualifications, in making its evaluation and recommendation of candidates, our Nominating and Governance Committee may consider, among other factors, diversity, age, skill, experience in the context of the needs of our Board, independence qualifications and whether prospective nominees have relevant business and financial experience, have industry or other specialized expertise, and have high moral character.

Our Nominating and Governance Committee may consider candidates for our Board from any reasonable source, including from a search firm engaged by our Nominating and Governance Committee or stockholder recommendations. Our Nominating and Governance Committee does not intend to alter the manner in which it evaluates candidates based on whether the candidate is recommended by a stockholder. However, in evaluating a candidate’s relevant business experience, our Nominating and Governance Committee may consider previous experience as a member of our Board.

In addition, our Board has delegated to our Nominating and Governance Committee the responsibility for establishing, implementing and monitoring the compensation for our directors. The

-92-

Nominating and Governance Committee establishes, reviews and approves the compensation of our directors and makes appropriate adjustments based on our performance, duties and responsibilities and competitive environment. Our Nominating and Governance Committee’s primary objectives in establishing and implementing director compensation are to:

• ensure the ability to attract, motivate and retain the talent necessary to provide qualified board leadership; and

• use the appropriate mix of long-term and short-term compensation to ensure high board/committee performance.

All of the current members of our Nominating and Governance Committee are independent as defined under the NYSE’s listing standards. During 2011, the Nominating and Governance Committee, then consisting of Mr. Benson (Chairman), Mr. Roemer and Mr. Stewart, did not hold any meetings. In order to ensure that our Nominating and Governance Committee is fully independent by July 28, 2012, the one year anniversary of the effectiveness of our IPO Registration Statement, on February 27, 2012, Mr. Stewart was removed from our Nominating and Governance Committee and Messrs. Friedman and Wommack were appointed to the Committee and its size increased to four members.

Corporate Governance

We are committed to adhering to sound principles of ethical conduct and corporate governance and have adopted corporate policies and practices that promote the effective functioning of our company and to ensure that it is managed with integrity and in our stockholders’ best interests. These corporate policies and practices include the Corporate Governance Guidelines for the Board, the Code of Business Conduct and Ethics for our employees and directors, the Financial Code of Ethics for our senior financial and accounting officers, the Whistleblower Policy and charters for the Audit Committee, Compensation Committee and Nominating and Governance Committee. Each of these documents is available on our website atwww.cjenergy.com and stockholders may obtain printed copies, free of charge, by sending a written request to C&J Energy Services, Inc., located at 10375 Richmond Ave., Suite 2000, Houston, TX 77042, Attn: Corporate Secretary.

Corporate Governance Guidelines

On July 14, 2011, our Board adopted the Corporate Governance Guidelines (the “Guidelines”). Among other matters, the Guidelines include the following:

Director Qualification Standards

• The Nominating and Governance Committee of our Board is responsible for evaluating candidates for nomination to our Board, and will conduct appropriate inquiries into the backgrounds and qualifications of possible candidates.

• A majority of directors on the Board will be “Independent” as defined by the listing requirements of the NYSE. Each year, the Nominating and Governance Committee will review the relationships between us and each director and will report the results of its review to the Board, which will then determine which directors satisfy the applicable independence standards.

-93-

• Our Board’s size is fixed from time to time pursuant to our certificate of incorporation and bylaws. Pursuant to our certificate of incorporation, there shall be seven directors on the Board, unless otherwise specified in, or determined in the manner provided in, our bylaws. Pursuant to our bylaws, the number of directors shall be fixed from time to time by the Board pursuant to a resolution of the Board. Our Board currently consists of seven directors.

Director Responsibilities

• The basic responsibility of each director is to exercise his or her business judgment to act in what he or she reasonably believes to be in the best interests of us and our stockholders.

• Directors are expected to attend Board meetings and meetings of committees on which they serve, and to spend the time needed and meet as frequently as necessary to properly discharge their responsibilities. Attendance at Board and committee meetings shall be considered by the Nominating and Governance Committee in assessing each director’s performance.

• Directors are encouraged to attend the annual meeting of stockholders

Director Access to Management and Independent Advisors

• Directors have complete and unfettered access to our senior management and independent advisors.

• Our Board has the right at any time to retain independent outside financial, legal or other advisors, without obtaining the approval of any officer in advance.

Chief Executive Officer Evaluation and Management Succession

• Each year, the Nominating and Governance Committee leads our Board in the annual performance review of our management, including our Chief Executive Officer.

• The Nominating and Governance Committee is responsible for oversight relating to management and board succession planning.

Annual Performance Evaluation, Director Orientation and Continuing Education

• The Nominating and Governance Committee leads the annual performance review of our Board and its committees.

• The Nominating and Governance Committee is responsible for developing and annually evaluating orientation and continuing education programs for directors.

Financial Code of Ethics for Chief Executive Officer, Chief Financial Officer, Controller and Certain Other Senior Financial Officers

On July 14, 2011, our Board adopted a Financial Code of Ethics for our Chief Executive Officer, our Chief Financial Officer, our Controller and other senior financial and accounting officers.

-94-

Any change to, or waiver from, the Financial Code of Ethics will be disclosed on our website within two business days after such change or waiver. Among other matters, the Financial Code of Ethics requires each of these officers to:

• act ethically with honesty and integrity, including the ethical handling of actual or apparent conflicts of interest between personal and professional relations;

• avoid conflicts of interest and disclose any material transactions or relationships that reasonably could be expected to give rise to a conflict of interest;

• work to ensure that we fully, fairly and accurately disclose information in a timely and understandable manner in all reports and documents that we file with the SEC and in other public communications made by us;

• comply with applicable governmental laws, rules and regulations; and

• report any violations of the Financial Code of Ethics to the chairman of our Audit Committee.

Corporate Code of Business Conduct and Ethics

On July 14, 2011, our Board adopted a Corporate Code of Business Conduct and Ethics, which sets forth the standards of behavior expected of our directors, officers and other employees. Among other matters, the Corporate Code of Business Conduct and Ethics is designed to deter wrongdoing and to promote:

• honest and ethical dealing with each other, with our clients and vendors, and with all other third parties;

• respect for the rights of fellow employees and all third parties;

• equal opportunity, regardless of age, race, gender, sexual orientation, religion, national origin, marital status, citizenship status, veteran status or disability;

• fair dealing with the our customers, suppliers, competitors and employees;

• avoidance of conflicts of interest;

• compliance with all applicable laws and regulations;

• the protection and proper use of our assets; and

• the reporting of any violations of the Corporate Code of Business Conduct and Ethics to the appropriate personnel.

-95-

Item 11. Executive Compensation

EXECUTIVE COMPENSATION AND OTHER INFORMATION

Compensation Discussion and Analysis

Executive Summary

This Compensation Discussion and Analysis provides information about our compensation objectives and policies for the executives who served as our principal executive officer, our principal financial officer and our other three most highly-compensated executive officers during fiscal year 2011, and is intended to place in perspective the information contained in the executive compensation tables that follow this discussion. This Compensation Discussion and Analysis provides a general description of our compensation program and specific information about its various components, which are largely base salaries, short- and long-term incentive and retention programs, retirement plans and health and welfare benefits.

Throughout this discussion, the following individuals are referred to as the “named executive officers” and are included in the Summary Compensation Table and other compensation tables that follow this Compensation Discussion and Analysis:

• Joshua E. Comstock —Chief Executive Officer, President and Chairman

• Randall C. McMullen, Jr. —Executive Vice President, Chief Financial Officer

• Bretton W. Barrier — Chief Operating Officer

• Theodore R. Moore —Vice President, General Counsel and Corporate Secretary

• J.P. “Pat” Winstead —Vice President, Sales and Marketing

Compensation Philosophy

Following our IPO, we have undertaken to design compensation for our employees, including our named executive officers, that includes a large component of incentive compensation based on our performance and the individual successes and contributions of our employees. Our equity-based compensation program is currently focused on providing stock option awards to our employees, which will only provide value to each holder in the event that our stock price increases over time, and certain terminations or poor company performance could result in the forfeiture or non-realization of the award without value. Our named executive officers are eligible to receive bonus awards only following our Compensation Committee’s determination that we completed a successful year and that the individual executive made significant contributions to that success. We believe that such compensation elements communicate to our executives that they will be paid for performance, and it aligns the interests of our executive officers with our shareholders’ interests.

We expect that our Compensation Committee will continue to design our executive compensation policies in a manner that allows us to continue to attract and retain individuals with the background and skills necessary to successfully execute our business strategy in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interests with our shareholders, and to reward individual and overall success in reaching such

-96-

goals. We expect that as we become accustomed to operating as a public company we may also incorporate additional performance metrics and designated target goals into our compensation program for bonuses and equity-based compensation awards. We expect our Compensation Committee to continue to work with its independent compensation consultant to assist in further tailoring our compensation program to that of a public company within our industry.

In designing our executive compensation program, our Compensation Committee relies on three primary elements of compensation (in addition to other benefits) — salary, cash bonus and long-term equity incentive awards. We believe that annual cash bonuses and equity-incentive awards are flexible in application and can be tailored to meet our compensation objectives, while still providing the executives with a performance-based incentive. The determination of an employee’s cash bonus will reflect our Compensation Committee’s assessment of the employee’s relative contribution to achieving or exceeding our annual, near-term goals. We anticipate that the determination of an employee’s long-term equity incentive awards will be based, in large part, on the employee’s demonstrated and expected contribution to our longer term performance objectives.

Objectives of Our Executive Compensation Program

The objectives of our compensation program are to keep compensation consistent with our strategic business and financial objectives and competitive within our industry, and to assure that we attract, motivate, and retain talented executive personnel.

Key Components of Our Executive Compensation Programs

Our compensation and benefits programs have historically consisted of the following key components, which are described in greater detail under “— Components of Our Executive Compensation Program”:

• Base salary;

• Bonus awards;

• Stock options;

• Severance and change in control benefits; and

• Other benefits.

We maintain employment agreements with our named executive officers (other than Mr. Winstead), and provide individual stock option agreements to each recipient of a stock option award, that govern the terms and conditions of these compensation elements.

Role of Compensation Committee and Named Executive Officers in Setting 2011 Compensation

Prior to our IPO, as a private company, our executive compensation decisions were primarily made either (1) in accordance with the terms of existing employment agreements with our executive officers, or (2) on an ad hoc basis and at the discretion of our private equity majority holders and certain members of our senior management after considering the overall performance of our company, the employee’s contribution to our overall performance, and the employee’s total compensation

-97-

package relative to other employees. In February 2011, however, our Board of Directors established an independent Compensation Committee that has the authority to oversee our executive compensation program and to implement any formal equity-based compensation plans or policies that the committee deems appropriate for our employees, including our named executive officers. We anticipate that our Compensation Committee will continue to consult with certain of our executive officers regarding our compensation and benefit programs, other than with respect to such executive officer’s own compensation and benefits, but the Compensation Committee is ultimately responsible for making all compensation decisions for the named executive officers. For the 2011 year, the Compensation Committee did consult with Mr. Comstock when determining whether, and to what extent, certain employees should receive bonuses in connection with the IPO.

     Role of Compensation Consultants in Setting 2011 Compensation

Our Compensation Committee has the authority to engage a compensation consultant at any time if the committee determines that it would be appropriate to consider the recommendations of an independent outside source. During the 2011 year, the Compensation Committee chose to engage Pearl Meyer & Partners (“Pearl Meyer”), an independent compensation consultant. Pearl Meyer reviewed both our executive compensation program and our non-executive director compensation program for the 2011 year and produced year-end compensation reports for the Compensation Committee in December of 2011. These reports were utilized by the Compensation Committee when making certain compensation decisions for the executives and the non-executive directors for the 2011 and 2012 years, although the Compensation Committee is responsible for all final decisions regarding compensation.

Pearl Meyer also provided the Compensation Committee with recommendations and advice during the process of selecting an appropriate peer group for compensation purposes. The Compensation Committee informed Pearl Meyer that its general criteria for selecting a peer group consisted of:

• companies that are direct competitors for the same space, products and/or services;

• companies that competed with us for the same executive team talent;

• companies in a similar SIC code or sector;

• companies that generally are subject to the same market conditions (or specifically, oilfield services companies); and

• companies that are tracked similarly or which are considered comparable investments by outside analysts.

The Compensation Committee and Pearl Meyer determined that an appropriate peer group should consist of 10 to 15 companies, and companies that are most statistically related to us with similar revenue size. After consultation with management and analyzing the research completed by

-98-

Pearl Meyer, the Compensation Committee determined that our peer group should consist of the following 16 companies:

Basic Energy Services, Inc.	Oceaneering International, Inc.
Complete Production Services, Inc.	Oil States International, Inc.
Dresser-Rand Group Inc.	Patterson-UTI Energy, Inc.
Exterran Holdings, Inc.	Pioneer Drilling Company
Global Industries, Ltd.	RPC, Inc.
Helmerich & Payne, Inc.	Superior Energy Services, Inc.
Key Energy Services, Inc.	Tesco Corporation
Newpark Resources, Inc.	TETRA Technologies, Inc.

Components of Executive Compensation Program

In anticipation of our IPO, we elected to enter into new employment agreements with Messrs. Comstock and McMullen in December 2010 to establish agreements that reflect the increased responsibilities associated with being the Chief Executive Officer and Chief Financial Officer of a publicly traded company. Additionally, our significant growth over the last few years resulted in a dramatic increase in Mr. Barrier’s duties and responsibilities as Chief Operating Officer and our IPO further expanded his role within our company. As a result, our Board of Directors determined it was appropriate to enter into an employment agreement with Mr. Barrier at the same time we entered into new agreements with Messrs. Comstock and McMullen. When Mr. Moore joined us we anticipated that he would also work as a key employee at our company and so we chose to enter into an employment agreement with him that was similar in form to Mr. Barrier’s agreement.

Base Salary

Each named executive officer’s base salary is a fixed component of compensation that may be annually adjusted by the Compensation Committee. We generally do not adjust base pay for our named executive officers based strictly on our performance, but take individual accomplishments and market trends into account as well. As such, base pay functions as an important counterbalance to incentive, discretionary, and equity compensation, all of which are generally contingent on our performance or success. The determination as to the reasonableness of a named executive officer’s 2011 base salary has been made by our Board of Directors with consultation with our Chief Executive Officer based on their collective extensive experience in the energy industry. We review the base salaries for each named executive annually as well as at the time of any promotion or significant change in job responsibilities, and in connection with each review consider individual and company performance over the course of that year. The total base salary received by each named executive for 2011 is reported in the Summary Compensation Table.

For the 2011 year, our named executive officers’ base salaries were as follows: Mr. Comstock, $625,000; Mr. McMullen, $450,000; Mr. Barrier, $325,000; Mr. Moore, $250,000 and Mr. Winstead, $200,000. These base salaries were set at levels that reflect the increase in duties and responsibilities of our named executive officers resulting from the continued growth of our company.

-99-

Bonus Awards

Annual Cash Bonus. The employment agreements for Messrs. Comstock, McMullen, Barrier and Moore provide for annual cash bonuses so long as we achieve certain targets established by our Compensation Committee. For 2011, the Compensation Committee determined to award annual cash bonuses to Messrs. Comstock, McMullen, Barrier and Moore based upon its assessment of our overall performance at the end of 2011 and each executive officer’s contribution to our overall performance. The Compensation Committee also discussed the annual cash bonuses with Pearl Meyer and requested their thoughts and recommendations regarding bonus target ranges that are set forth in the employment agreements.

The target bonus set for each named executive officers for the 2011 year, as well as the actual payout amounts, are set forth below:

Name	Target Amount as Percentage of 2011 Salary	Actual Payment as Percentage of 2011 Salary	Actual Payment Amount ($)
Mr. Comstock	150-200%	200%	1,250,000
Mr. McMullen	100-150%	150%	675,000
Mr. Barrier	75-100%	100%	325,000
Mr. Moore	25-50%	50%	125,000
Mr. Winstead	25-50%	50%	100,000

Bonus payments provided under the employment agreements, if any, will typically be paid between January 1 and March 15 of the year following the year to which the bonus is applicable. In the event that any executive is terminated for cause during the applicable year, however, they forfeit any right to receive a bonus for that year.

Registration Statement Bonus. Messrs. Comstock and McMullen’s employment agreements provide for the payment of a cash bonus to each of them in the amount of $125,000 if a shelf registration statement for our IPO was declared effective by the SEC on or prior to June 29, 2011. We chose to delay the effectiveness of our shelf registration statement in order to consummate our IPO. Taking this into consideration, on July 14, 2011 our Compensation Committee determined to award each of Messrs. Comstock and McMullen these bonuses contingent upon our shelf registration statement being declared effective within 60 days of the closing of the IPO. Due to the successful completion of our IPO and our shelf registration statement becoming effective within the 60 day period following the closing of our IPO, the bonuses were paid to each of Messrs. Comstock and McMullen on October 3, 2011. These bonuses were intended to reward the achievement of a milestone for our company on a timeline specified by our Compensation Committee to achieve parallel business goals. The shelf registration statement bonus opportunity was made available only to Messrs. Comstock and McMullen because their extraordinary individual contributions were the largest drivers of the timely achievement of this milestone and they had more control over the factors that contributed to the achievement of our goal than our other named executive officers.

IPO Bonuses. Our Compensation Committee has the authority to award additional incentive bonus compensation to our named executive officers in the event that it deems appropriate. On March 7, 2011 our Board of Directors determined that the registration statement bonuses provided in Messrs. Comstock and McMullen’s employment agreements should be increased to adequately compensate them for the additional work required to complete our IPO. Our Board of Directors

-100-

increased such incentive compensation by awarding additional discretionary bonuses in the amounts of $200,000 and $100,000 for Messrs. Comstock and McMullen, respectively, contingent upon the successful completion of our IPO. Additionally, on March 7, 2011 our Compensation Committee determined that Mr. Barrier should receive a discretionary bonus in the amount of $50,000 contingent upon and payable concurrently with the successful completion of our IPO. On July 14, 2011, our Compensation Committee determined that Mr. Moore should receive a discretionary bonus in the amount of $50,000 contingent upon and payable concurrently with the successful completion of our IPO. This IPO bonus opportunity was granted to Mr. Moore due to the work he completed in connection with the IPO.

Stock Options

We grant stock options because options compensate our named executive officers only in the event of an increase in the market value of our common stock, thus aligning the interests of our named executive officers with those of our shareholders. We believe the three year vesting period associated with these stock option awards will mitigate any risk that they would be incentivized to take actions that may not be in the long-term interest of our shareholders in order to increase our share price in the near-term. Finally, we prefer to issue stock options because the compensation cost to us associated with options is generally fully deductible. Please read “— Tax Deductibility of Executive Compensation.”

Prior to December 23, 2010, all options granted to our named executive officers were granted under the C&J Energy Services, Inc. 2006 Stock Option Plan, the “2006 Plan.” The 2006 Plan provided for awards of incentive stock options, non-statutory stock options, restricted stock, and other stock based awards to employees, officers, directors, consultants and advisors. As of the end of fiscal year 2010, our named executive officers have been awarded only non-qualified stock options, and no other stock-based awards have been made under the 2006 Plan. Non-statutory stock options granted to our named executive officers vested 20% on the date of grant and another 20% on each of the first four anniversaries of the grant date. On December 23, 2010, the 2006 Plan was amended to provide that (i) no additional awards will be granted under the 2006 Plan, (ii) all awards outstanding under the 2006 Plan will continue to be subject to the terms of the 2006 Plan, and (iii) options to purchase all 237,927 shares awarded under the 2006 Plan vested and became exercisable in connection with the completion of the private placement of our common stock in December 2010. Additionally, on December 23, 2010, we granted the remaining 35,000 shares available for issuance under the 2006 Plan as follows: 17,500 options were granted to each of Messrs. Comstock and McMullen, which were fully vested on the date of grant and have an exercise price of $10.00 per share.

On December 23, 2010, we adopted the C&J Energy Services, Inc. 2010 Stock Option Plan, the “2010 Plan.” We use the 2010 Plan to grant equity awards to our employees, consultants, and outside directors. We originally reserved 5,699,889 shares for issuance under the 2010 Plan. The 2010 Plan allows us to grant non-statutory stock options and incentive stock options, although, to date, we have only granted non-statutory stock option awards to our named executive officers.

In February 2011 and July 2011, our Board of Directors concluded that the overall compensation package of certain of our employees, including certain named executive officers, was insufficient to meet our objective to retain talented executive personnel by providing both short-term and long-term incentive compensation. As a result, we awarded stock options to these employees under the 2010 Plan. In February, we granted 40,000 options to Mr. Moore as a sign-on inducement grant and we granted 40,000 options to Mr. Winstead as part of a larger equity grant to operational employees; in

-101-

July, we granted 275,000 options to Mr. Comstock, 200,000 options to Mr. McMullen, 100,000 options to each of Messrs. Barrier and Moore, and 85,000 options to Mr. Winstead, each in connection with the IPO and in satisfaction of 2011 long-term incentive awards. The amount of each grant was determined by our Board of Directors based on each executive’s duties and responsibilities and each executive’s contribution to our overall performance in 2010 and 2011. All of the February 2011 and July 2011 stock option awards to employees vest equally on each of the first, second, and third anniversaries of the grant date and expire ten years following the grant date. All of the February 2011 options have an exercise price equal to the fair market value of our shares on the date of grant and all of the July 2011 options have an exercise price equal to the final IPO price per share.

For purposes of valuing the stock option awards that we have granted to our named executive officers, we are required to report the grant date fair value of awards under specific accounting principles within the tables that follow this Compensation Discussion and Analysis. The accounting valuations, however, do not provide an accurate account of the current settlement value of certain outstanding stock option awards. For example, the July stock option grants have exercise prices that are currently above the market value of our stock, so an exercise of the stock options at today’s prices would not provide immediate value to the holder (these options are considered “underwater”). The July grants will provide value to the named executive officers only if our common stock increases in value to a price that exceeds the exercise price for that award. The values assigned to the portion of the “Option Awards” column of the “Summary Compensation Table” that relate to the July grants are based upon certain long-term assumptions and not on the value that each named executive officer actually received during the 2011 year.

The Compensation Committee does not expect that the grant date fair value of stock option awards that we granted to named executive officers and other key employees during the 2010 and 2011 years will be continued at the same level in future years. Certain of the stock option awards that were granted to management employees in recognition of the extraordinary work that each member of our management team provided in connection with our growth and transition to a public company were considered special grants. The Compensation Committee consulted with Pearl Meyer regarding special IPO-related grants of equity compensation awards within our peer group and found that the level of one-time IPO-related equity grants within our peer group was typically significantly higher than the number of awards that the company would grant on a more typical annual schedule. On a going-forward basis, we expect that our named executive officers will receive annual equity-based compensation awards in order to maintain a strong tie between our executive’s interests and those of our shareholders. We expect that annual equity-based compensation grants will be targeted at or near the median of the market norm in our peer group for similar annual grants.

Severance and Change in Control Benefits

We believe it is important that Messrs. Comstock, McMullen, Barrier and Moore focus their attention and energy on our business without any distractions regarding the effects of a termination that is beyond their control or our change in control. Therefore, their employment agreements each provide that they will be entitled to receive severance benefits and accelerated vesting of their options in the event their employment is terminated under certain circumstances. Specifically, all payment obligations to Messrs. Comstock, McMullen, Barrier and Moore associated with a change in control are “double trigger” payments, which require termination of employment within the two years following a change in control to receive the benefit. Our board of directors believed that a double trigger payment was more appropriate than a single trigger payment (where a payment is made upon

-102-

the occurrence of a change in control alone) because it financially protects the employee if he is terminated following a change in control transaction, without providing a potential windfall if the employee is not terminated. For more detailed information regarding our severance and change in control benefits, please read “— Potential Payments upon Termination or Change in Control.”

Other Benefits

Each of our named executive officers is provided with certain perquisites, including the use of a company-owned vehicle or an annual automobile allowance and a health care subsidy. As more fully described in the section titled “Related Party Transactions,” Mr. Comstock owns a personal aircraft that Mr. Comstock uses for personal and business travel. We partially reimburse Mr. Comstock for the expenses associated with business travel. In the event that Mr. Comstock’s family accompanies him on one of these business-related trips, the amounts that we reimburse Mr. Comstock with respect to his family’s travel costs are reported as compensation to Mr. Comstock in the “All Other Compensation” column of the Summary Compensation Table. Other benefits received by each of our named executive officers for the fiscal year ended December 31, 2011 are disclosed in the Summary Compensation Table.

We do not maintain a defined benefit or pension plan for our executive officers or other employees because we believe such plans primarily reward longevity rather than performance. Nevertheless, we recognize the importance of providing our employees with assistance in saving for their retirement. We, therefore, maintain a retirement plan, or the 401(k) Plan, that is qualified under Section 401(k) of the Internal Revenue Code of 1986, as amended, or the Code. Following the completion of one year of service, we offer matching contributions for each of our employees, including our named executive officers, up to 4% of their qualifying compensation each year, subject to certain limitations imposed by the Code. Amounts of the matching contributions to the 401(k) Plan during 2011 on behalf of our named executive officers are disclosed in the Summary Compensation Table.

Stock Ownership Guidelines

Stock ownership guidelines have not been implemented for our named executive officers or directors at this time. We will continue to periodically review best practices and reevaluate our position with respect to stock ownership guidelines.

Tax Deductibility of Executive Compensation

Limitations on deductibility of compensation may occur under Section 162(m) of the Internal Revenue Code. An exception applies to this deductibility limitation for a limited period of time in the case of companies that become publicly traded through an IPO. In addition, following such limited period of time, an exception to the $1 million limit applies with respect to certain performance-based compensation.

Although deductibility of compensation is preferred, tax deductibility is not a primary objective of our compensation programs. We believe that achieving our compensation objectives is more important than the benefit of tax deductibility of compensation, and prefer to maintain flexibility in how we compensate our executive officers that may result in limited deductibility of amounts of compensation from time to time.

-103-

Relation of Compensation Policies and Practices to Risk Management

We anticipate that our compensation policies and practices will be designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk-taking. However, at this time our Compensation Committee retains a significant amount of discretion with respect to the compensation packages of our named executive officers, which we believe prevents management from entering into actions that could have a material adverse effect on us in the long-run to simply achieve a specific short-term goal. We also believe that the compensation program that our general employee population is eligible to receive does not entice the employees to take unnecessary risks in their day to day activities.

We expect our compensation arrangements to contain a number of design elements that serve to minimize the incentive for taking unwarranted risk to achieve short-term, unsustainable results. Those elements include delaying the rewards and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices.

In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees, including our named executive officers, are reasonably likely to have a material adverse effect on us.

Actions Taken For the 2012 Fiscal Year

On December 15, 2011, the Compensation Committee approved adjustments to the base salaries and bonus targets for Messrs. Comstock, McMullen, Barrier and Moore for 2012. The Compensation Committee reviewed the company’s 2011 performance and the individual contributions that each named executive officer made to the company for 2011. The Compensation Committee also discussed base salary and bonus targets with Pearl Meyer, and requested that Pearl Meyer provide the Compensation Committee with its recommendations or thoughts regarding base salary and bonus target levels that were in such named executive officer’s current employment agreements in comparison to the base salary and bonus target levels of similarly situated executives at companies within our peer group. Based upon the studies conducted by Pearl Meyer at the end of the 2011 year, our named executive officers’ base salaries were on average below the market median at the 28th percentile (with the exception being Mr. McMullen, who has operational responsibilities that place a premium on his value to us, and who was estimated to be closer to the 67th percentile with respect to his base salary). The 2011 base salaries and bonus levels positioned the target total cash compensation for such executives, on average, in the 39th percentile in our market.

After considering market analysis with respect to executive base salaries within our peer group and individual responsibilities and contributions to the company, the Compensation Committee determined that the base salaries of Messrs. Comstock, McMullen, Barrier and Moore should be set at the following levels beginning on January 1, 2012: Mr. Comstock, $725,000; Mr. McMullen, $475,000; Mr. Barrier, $350,000; and Mr. Moore, $300,000. Target bonus levels for each of the named executive officers were set at the following levels for the 2012 year: Mr. Comstock, 100-200% of 2012 base salary; Mr. McMullen, 100-200% of 2012 base salary; Mr. Barrier, 75-150% of 2012 base salary; and Mr. Moore, 50-100% of 2012 base salary.

The Compensation Committee has not made any decisions regarding equity-based compensation awards for 2012 as of the date of this filing. The Pearl Meyer report provided to the

-104-

Compensation Committee at the end of the 2011 year reported that our named executive officers had received a number of stock option awards during the 2011 year that placed their equity award values above market within our peer group for 2011. The Compensation Committee recognizes that the special IPO-related grants were the most significant reason for this finding, and also recognizes that these studies were based upon the accounting grant date fair values for the awards rather than the actual values that each executive received during the 2011 year. In contrast to the accounting values that are reported for the 2011 stock option awards in the tables that follow, certain of the awards are currently underwater and could not be exercised for any value at this time. The Compensation Committee expects that it will have further conversations with Pearl Meyer during the 2012 year regarding the structure and design of our equity compensation programs for the 2012 year and going forward.

Summary Compensation Table

The table below sets forth the annual compensation earned during the 2010 and 2011 fiscal year by our named executive officers:

Name and Principal Position	Year		Salary($)(1)	Bonus ($)(2)	Option Awards ($)(3)		All Other   Compensation   ($)(4)	Total ($)
Joshua E. Comstock		2011	625,000	1,578,000		5,275,440	53,849		7,532,289
Chief Executive Officer, President and Chairman
		2010	284,750	1,785,000		11,149,535	23,195		13,242,480
Randall C. McMullen, Jr.		2011	450,000	903,000		3,836,684	118,223		5,307,907
Executive Vice President, Chief Financial Officer
		2010	190,564	1,725,000		7,997,137	18,816		9,931,517
Bretton W. Barrier		2011	325,000	378,000		1,918,342	28,362		2,649,704
Chief Operating Officer
		2010	187,824	187,424		3,152,399	24,595		3,552,242
Theodore R. Moore		2011	229,167	177,500		2,185,133	18,979		2,610,779
Vice President, General Counsel and Corporate Secretary
J.P. “Pat” Winstead		2011	200,000	103,000		1,924,717	27,962		2,255,679
Vice President, Sales and Marketing
		2010	163,584	2,141,035		—	24,595		2,329,214

(1) Mr. Moore joined us on February 1, 2011, thus salary amounts reported for him reflect amounts earned from February 1, 2011 to December 31, 2011. The amounts in this column for the 2010 year reflect the base salaries earned by each of the named executive officers during the 2010 fiscal year rather than the base salaries that were in effect at the end of the 2010 fiscal year, as salary levels were modified twice during the 2010 year.

(2) The amounts in this column for the 2011 year reflect amounts earned for the 2011 fiscal year. For Messrs. Comstock and McMullen, this amount also includes the shelf registration statement bonuses of $125,000, respectively. For Messrs. Comstock, McMullen, Barrier and Moore, this amount also includes IPO bonuses of $200,000, $100,000, $50,000 and $50,000, respectively.

(3) The amounts in this column for the 2011 year represent the grant date fair value of each stock option award granted under our 2010 Plan, computed in accordance with FASB ASC Topic 718. Please read Note 6 to our consolidated financial statements included in this Form 10-K for a discussion of the assumptions used in determining the grant date fair value of these awards. As more fully discussed within the Compensation Discussion and Analysis section above, these values do not necessarily reflect the value that each executive actually received during the applicable year, and actual values will not be determinable until the awards become vested and the executive exercises the award.

-105-

(4) The amounts in this column reflect the following payments to each of the named executive officers: $8,362 in the amount of subsidized health care benefits, excluding Mr. Moore who received $9,379; $9,800 for company matching contributions to each of the executive’s 401(k) Plan accounts, excluding Mr. Moore; for Messrs. Comstock, McMullen, Barrier, Moore and Winstead, $15,758, $14,443, $10,200, $9,600 and $9,800], respectively, for automobile allowances and related maintenance costs; for Mr. McMullen, $85,617 for certain relocation expenses paid pursuant to the terms of Mr. McMullen’s employment agreement; and for Mr. Comstock, $19,929 for the amounts of income that we imputed to Mr. Comstock during the 2011 year for the accompaniment of family members on business trips (while no additional direct operating costs with respect to the personal use of Mr. Comstock’s airplane is incurred in such situations, the value of personal use of the aircraft is imputed as income to him).

Grants of Plan-Based Awards for the 2011 Fiscal Year

Name	Grant Date	Option Awards:   Number of Securities Underlying Options(1)	Exercise or Base   Price of Option Awards ($)(2)	Grant Date Fair  Value of Stock and Option Awards ($)(3)
Joshua E. Comstock	7/28/2011	275,000	29.00	5,275,440
Randall C. McMullen, Jr.	7/28/2011	200,000	29.00	3,836,684
Bretton W. Barrier	7/28/2011	100,000	29.00	1,918,342
Theodore R. Moore	2/1/2011	40,000	10.00	266,791
	7/28/2011	100,000	29.00	1,918,342
J.P. “Pat” Winstead	2/3/2011	40,000	11.00	294,126
	7/28/2011	85,000	29.00	1,630,591

(1) Each stock option award reflected in this column was granted under the 2010 Plan.

(2) The exercise prices for the stock options granted February 1, 2011 and February 3, 2011 were based upon the fair market value of our common stock on the dates of grant, while the exercise price for the stock options granted July 28, 2011 was based upon the per share final initial IPO price.

(3) Amounts in this column represent the grant date fair value of each stock option award granted under our 2010 Plan, computed in accordance with FASB ASC Topic 718. As more fully discussed within the Compensation Discussion and Analysis section above, these values do not necessarily reflect the value that each executive actually received during the applicable year, and actual values will not be determinable until the awards become vested and the executive exercises the award.

The employment agreements for Messrs. Comstock, McMullen, Barrier and Moore set forth the duties of each executive’s position with us. The agreements have three year terms that extend from their effective dates, with one year term extensions thereafter absent either party providing notice of a non-renewal. The agreements set forth base salaries, annual bonus target ranges, and benefits such as health and retirement opportunities. The employment agreements provide that the executive will be entitled to receive annual equity awards from the 2010 Plan or future equity incentive plans, although the terms and conditions of such awards will be determined by the Compensation Committee on an individual basis and governed by individual award agreements. For potential severance and change in control benefits that are provided within the employment agreements, see the “— Potential Payments upon Termination or Change in Control” section below.

The stock option awards from our 2010 Plan are governed by individual stock option agreements. Each of the awards was granted with a ten-year expiration date, measured from the grant date for the awards. The stock options are subject to forfeiture prior to vesting, which will occur in three equal installments on each of the yearly anniversaries of the grant date. Vesting for the options will accelerate upon certain terminations of employment, however, as described in greater detail below in “— Potential Payments Upon Termination or Change in Control.”

-106-

The amount of salary and bonus that each of the named executive officers received for the 2011 year in relation to their respective total compensation package for the 2011 year is as follows:

Percentage of Salary and Bonus in Comparison to Total Compensation

Name	Salary Percentage of     Total Compensation
Joshua E. Comstock		29	%
Randall C. McMullen, Jr.		25	%
Bretton W. Barrier		27	%
Theodore R. Moore		16	%
J.P. “Pat” Winstead		13	%

Outstanding Equity Awards at 2011 Fiscal Year-End

The following table provides information on the current stock option and stock award holdings by the named executive officers. This table includes unexercised options. The vesting dates for each award are shown in the accompanying footnotes. There were no other outstanding equity awards as of December 31, 2011 other than options.

Name	Number of Securities Underlying Unexercised  Options Exercisable	Number of Securities Underlying Unexercised Options     Unexercisable	Option Exercise     Price ($)	Option Expiration  Date
Joshua E. Comstock	17,500 (1)	1,108,312 (2)	10.00	12/23/2020
	554,156 (3)		10.00	12/23/2020
	105,000 (1)		1.43	11/11/2018
	525,000 (1)		1.43	11/1/2016
		275,000 (4)	29.00	7/28/2021
Randall C. McMullen, Jr.	17,500 (1)	791,651 (2)	10.00	12/23/2020
	395,826 (3)		10.00	12/23/2020
	161,000 (1)		1.43	11/11/2018
		200,000 (4)	29.00	7/28/2021
Bretton W. Barrier	158,330 (3)	316,661 (2)	10.00	12/23/2020
	157,500 (1)		1.43	1/30/2017
		100,000 (4)	29.00	7/28/2021
Theodore R. Moore		40,000 (5)	10.00	2/1/2021
		100,000 (4)	29.00	7/28/2021
J.P. “Pat” Winstead	35,000 (1)		1.43	11/1/2016
	42,000 (1)		1.43	11/11/2018
		40,000 (6)	11.00	2/3/2021
		85,000 (4)	29.00	7/28/2021

(1) Each of these stock options were granted from the 2006 Plan and became fully vested on December 23, 2010.

(2) Each of these stock options were granted from the 2010 Plan on December 23, 2010 and will vest in equal one third installments on each of December 23, 2012, and December 23, 2013.

(3) Each of these stock options were granted from the 2010 Plan on December 23, 2010 and became vested on December 23, 2011.

(4) Each of these stock options were granted from the 2010 Plan and will vest in equal installments on each of July 28, 2012, July 28, 2013 and July 28, 2014.

(5) Each of these stock options were granted from the 2010 Plan and will vest in equal installments on each of February 1, 2012, February 1, 2013 and February 1, 2014.

(6) Each of these stock options were granted from the 2010 Plan and will vest in equal installments on each of February 3, 2012, February 3, 2013, and February 3, 2014.

-107-

Option Exercises in the 2011 Fiscal Year

	Option Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)
Joshua E. Comstock	N/A	N/A
Randall C. McMullen, Jr.	87,500	1,507,750 (1)
Bretton W. Barrier	N/A	N/A
Theodore R. Moore	N/A	N/A
J.P. “Pat” Winstead	N/A	N/A

(1) This amount was calculated by multiplying the difference in the exercise price of the stock options ($1.43) and the market price of our common stock on the date of exercise ($18.66) and multiplying that amount by 87,500. As of the date of this filing, Mr. McMullen is still the owner of the shares of common stock that he received upon the exercise of the stock options, and the value that he may actually realize upon the sale of such shares in the future cannot be determined until the date of such sale.

Pension Benefits

While we provide our employees with the 401(k) Plan, we do not currently maintain a defined benefit pension plan. Please read “— Components of Executive Compensation Program — Other Benefits.”

Nonqualified Deferred Compensation

We do not provide a nonqualified deferred compensation plan for our employees at this time.

Potential Payments Upon Termination or Change in Control

Employment Agreements

The employment agreements between us and Messrs. Comstock, McMullen, Barrier and Moore contain certain severance provisions. We believe that severance provisions should be included in employment agreements as a means of attracting and retaining executives and to provide replacement income if their employment is terminated because of a termination that may be beyond the executive’s control, except in certain circumstances such as when there is cause.

If we terminate Messrs. Comstock, McMullen, Barrier, or Moore’s employment for cause, or if such an executive resigns without good reason, then that executive will be paid (i) (A) that executive’s base salary earned through the date of termination and (B) any accrued but unpaid vacation pay due to the executive ((A) and (B) together, the “Accrued Obligations”) and (ii) unreimbursed expenses.

If Messrs. Comstock, McMullen, Barrier or Moore’s employment is terminated by the executive for good reason or by us other than for cause, because of death or disability, or because we choose not to renew the executive’s employment agreement (in each case, other than during a change in control period), then the named executive officer will be entitled to receive: (i) payment of the

-108-

accrued obligations and any unreimbursed expenses, (ii) any unpaid bonuses owed to the executive for a completed calendar year that have yet to be paid, (iii) if the executive’s termination is after June 30, then a pro-rata payment of his annual bonus for the year of his termination (but no longer than two years from the date of termination), (iv) immediate vesting of all unvested stock options awarded to the executive under any plan, (v) for Messrs. Comstock, McMullen or Barrier, salary continuation severance payments based on the executive’s base salary in effect on the date of termination continuing for the longer of (A) the remainder of the term of the executive’s employment agreement and (B) one year from the date of termination, and for Mr. Moore salary continuation severance payments based on his base salary in effect on the date of termination continuing for ninety (90) days from the date of termination, and (vi) a lump-sum payment of an amount equal to all Consolidated Omnibus Budget Reconciliation Act, or COBRA, premiums that would be payable during the period described for each executive in (v). Notwithstanding (v) in the prior sentence, if the termination occurs because we choose not to renew the executive’s employment agreement then the period in (v) shall instead be twelve (12) months if the term of the employment agreement ends on the third anniversary of the effective date of the employment agreement, six (6) months if the term of the agreement ends on the fourth anniversary of the effective date of the employment agreement, and three (3) months (or such longer time as may be provided under our severance policies generally) if the term of the employment agreement ends on or after the fifth anniversary of the effective date of the employment agreement. Our obligation to pay the executive items (iii) through (vi) of this paragraph is subject to the executive’s execution of a release of claims against us within 50 days after the date of his termination of employment.

If Messrs. Comstock, McMullen, Barrier or Moore’s employment is terminated by reason of death or disability, the employment agreements provide that the executive will be entitled to: (i) payment of the Accrued Obligations, (ii) payment of any unreimbursed expenses, (iii) any unpaid bonuses owed to the executive for a completed calendar year that have yet to be paid, (iv) if the executive’s termination is after June 30, then a pro-rata payment of his annual bonus for the year of his termination, and (v) the payment of any and all benefit obligations due to the named executive officer or his estate (as the case may be) available in which the executive participated.

If, during the two years following a change in control (as defined in the named executive officers’ employment agreements), we terminate a named executive officer’s employment without cause, such executive resigns for good reason, or we choose not to renew the executive’s employment agreement, then the named executive officer will be entitled to receive: (i) payment of the Accrued Obligations and any unreimbursed expenses, (ii) any unpaid bonuses owed to the executive for a completed calendar year that have yet to be paid, (iii) if the executive’s termination is after June 30, then a pro-rata payment of his annual bonus for the year of his termination, (iv) immediate vesting of all unvested stock options awarded to the executive under any plan, (v) salary continuation severance payments based on the executive’s base salary in effect on the date of termination continuing for the longer of (A) the remainder of the term of the executive’s employment agreement and (B) two years from the date of termination, and (vi) a lump-sum payment of an amount equal to all COBRA premiums that would be payable during the period described in (v) for Messrs. Comstock, McMullen and Barrier, and for a ninety (90) day period for Mr. Moore. Our obligation to pay the executive items (iii) through (vi) of this paragraph is subject to the executive’s execution of a release of claims against us within 50 days after the date of his termination of employment.

If any portion of the payments under this agreement, or under other agreements with the named executive officers, would constitute “excess parachute payments” and would result in the imposition of

-109-

an excise tax on the executive, then the payments made to the named executive officer will either be (i) delivered in full, or (ii) reduced in accordance with the executive’s employment agreement until no portion of the payments are subject to an excise tax, whichever results in the receipt by the named executive officer of the greatest benefit on an after-tax basis.

All payments of the Accrued Obligations and unreimbursed expenses would be paid to the named executive officer within thirty (30) days after the date of the executive’s termination of employment. So long as (i) the named executive officer signs a release on or before the 50th day following the executive’s termination of employment and (ii) the executive complies with the confidentiality, noncompetition, non-disclosure, and non-solicitation provisions of the executive’s employment agreement, all salary continuation payments will begin, and all lump-sum COBRA payments will be made, on the 60th day following the executive’s termination of employment. In general, breach by a named executive officer of the confidentiality, noncompetition, non-disclosure, and non-solicitation provisions of the executive’s employment agreement may result in (A) the termination of severance payments to the executive at the Board’s discretion and (B) if a court finds that the executive has breached the employment agreement in this way, the repayment by the executive of all severance payments previously made.

All payments of deferred compensation paid upon a termination of employment will be paid on the second day following the sixth month after the named executive’s termination of employment if so required by Section 409A of the Code.

Stock Option Plans and Agreements

The stock option agreements for the 2010 Plan option grants to our named executive officers that have employment agreements state that if any of the executives cease to provide services to us (other than because of their death or disability), then their options that were previously vested but unexercised will terminate at the end of the 90th day following the date of their termination of service. Further, if any of our named executive officers experiences a termination of employment (i) by us without cause, (ii) because we decide not to renew the executive’s employment agreement, or (iii) by the executive for good reason, then any unvested options awarded to that executive under the 2010 Plan will immediately become fully vested and exercisable. If a named executive officer experiences a termination of employment other than of a type described in (i), (ii), or (iii) of the immediately preceding sentence, then upon such a termination all unvested options will be forfeited. Finally, the stock option agreements provide that if a named executive officer’s employment is terminated by us for cause then all options granted to them under the 2010 Plan are forfeited upon the effective date of such termination.

Potential Payments Upon Termination or Change in Control Table

The following table quantifies the amounts that each of our named executive officers could be expected to receive upon a termination or a change in control, assuming that such an event occurred on December 31, 2011. Such amounts cannot be determined with any certainty outside of the occurrence of an actual termination or change in control event, and we have assumed that our common stock’s value of $20.93 per share on December 31, 2011 would be the value of any accelerated equity upon such a hypothetical termination or change in control event. Due to the fact that certain outstanding stock options held by our named executive officers have exercise prices above $20.93, the table below only shows the hypothetical value that each individual would have received in connection with the

-110-

acceleration of the stock option awards that were both unvested and had exercise prices of less than $20.93 on December 31, 2011. We have also assumed for purposes of the table below that all Accrued Obligations and other similar expenses were paid current as of December 31, 2011. Any actual payments that may be made pursuant to the agreements described above are dependent on various factors, which may or may not exist at the time a change in control actually occurs and/or the named executive officer is actually terminated. Therefore, such amounts and disclosures should be considered “forward-looking statements.”

Name and Principal Position	Without Cause or Good Reason Termination, or  Non-Renewal Outside of  a Change in Control(1)($)	Without Cause or Good Reason Termination, or Non-Renewal in  Connection with Change  in Control ($)	Termination Due to   Death or Disability($)
Joshua E. Comstock
Salary and Bonus	2,447,917	2,500,000	1,250,000
Continued Medical	28,801	30,054	—
Accelerated Equity	12,113,850	12,113,850	6,056,925
Total	14,590,568	14,643,904	7,306,925
Randall C. McMullen, Jr.
Salary and Bonus	1,537,500	1,575,000	675,000
Continued Medical	28,801	30,054	—
Accelerated Equity	8,652,745	8,652,745	4,326,373
Total	10,219,046	10,257,799	5,001,373
Bretton W. Barrier
Salary and Bonus	947,917	975,000	325,000
Continued Medical	28,801	30,054	—
Accelerated Equity	3,461,105	3,461,105	1,730,552
Total	4,437,823	4,466,159	2,055,052
Theodore R. Moore
Salary and Bonus	187,500	645,833	125,000
Continued Medical	3,757	3,757	—
Accelerated Equity	437,200	437,200	145,730
Total	628,457	1,086,790	270,730

(1) Amounts reflected in the “Salary and Bonus” line of this column were calculated by using the base salary of each executive officer on December 31, 2011, and the full amount of the bonus that each of the executives received for the 2011 year pursuant to his employment agreement, due to the fact that a termination on the last day of the year would not have resulted in a pro-rata bonus but rather a bonus for the entire 2011 year.

Director Compensation

Beginning on February 3, 2011, the individuals that served on our Board of Directors that were not also employees received compensation for services they provided to us. The employee-directors, Messrs. Comstock and McMullen, do receive additional compensation for their services as directors. All compensation that Messrs. Comstock and McMullen received for their services to us during 2011 as employees has been described in the Compensation Discussion and Analysis and disclosed in the Summary Compensation Table above.

The remaining non-employee directors were compensated for their 2011 service on the Board of Directors with an annual fee of $35,000, a fee of $2,000 per board meeting attended in person or telephonically, as well as a $1,000 meeting fee for personal or telephonic attendance at committee meetings for any committee on which that director served.

-111-

Non-employee directors also received compensation for serving as the chairman of certain committees. Our Audit Committee chairman received an annual fee of $15,000, while our Nominating and Governance Committee chairman and our Compensation Committee chairman each received an annual fee of $10,000. During the 2011 year, Mr. Roemer served as the chairman of our Audit Committee, Mr. Benson served as the chairman of our Nominating and Governance Committee, and Mr. Wommack served as the chairman of our Compensation Committee.

Equity awards will also be granted to our non-employee directors on an annual basis. During the 2011 year, the non-employee directors received stock option awards fully vested as of the date of grant. The value of the annual equity award for 2011 was targeted at approximately $25,000 on the grant date, based on a Black-Scholes valuation model.

Name	Fees Earned or Paid in Cash ($)	Option Awards ($)(1)	All Other Compensation ($)	Total ($)
Darren M. Friedman	58,000	25,002	—	83,002
James P. Benson(2)	52,000	25,002	—	77,002
Michael Roemer	71,000	25,002	—	96,002
H. H. “Tripp” Wommack, III	68,000	25,002	—	93,002
C. James Stewart, III	50,000	25,002	—	75,002

(1) The amounts in this column represent the grant date fair value of each stock option award granted under our 2010 Plan, computed in accordance with FASB ASC Topic 718. Please read Note 6 to our consolidated financial statements included this Form 10-K for a discussion of the assumptions used in determining the grant date fair value of these awards. As of December 31, 2011, each non-employee director held 3,667 outstanding stock option awards.

(2) The fees earned by Mr. Benson are paid directly to Energy Spectrum Partners IV, LP (“Energy Spectrum”), our former sponsor. Under the terms of the Amended and Restated Stockholders’ Agreement, subject to retaining certain ownership thresholds, Energy Spectrum was entitled to appoint one director to our Board, currently Mr. Benson. Due to the decrease in Energy Spectrum’s ownership percentages, it is not entitled to appoint a director at this time. Please read “Certain Relationships and Related Party Transactions — Amended and Restated Stockholders’ Agreement.”

The Compensation Committee requested information from Pearl Meyer regarding the compensation provided to non-executive directors at our peer companies as of the end of the 2011 year. The Compensation Committee reviewed the findings that Pearl Meyer submitted and determined that certain modifications to the director compensation program would be appropriate for the 2012 year. Beginning on January 1, 2012, the non-executive directors will each receive a $50,000 annual retainer and meeting fees of $1,500 per meeting for each regular or special board meeting, and each committee meeting if held on a day different than on a full board meeting, each whether attended in person or by telephone. Committee chair fees for the Audit Committee will be $15,000, and $10,000 for each of the Compensation Committee and Nominating and Governance Committee chairs. Annual equity-based awards will be targeted at $120,000 and will be granted in the form of stock options, restricted stock, or some combination of both. Awards will be subject to a six (6) month vesting requirement, and sales restrictions that will lift in equal one-third installments on each of the first, second and third anniversaries of the grant date, with automatic accelerated vesting upon the resignation or non-election of such non-executive director to the Board.

Compensation Committee Interlocks and Insider Participation

Mr. Wommack (Chairman), Mr. Friedman, Mr. Benson, Mr. Roemer and Mr. Stewart have served on our Compensation Committee since its inception in February 2011. None of these directors

-112-

has ever served as one of our officers or employees. None of our executive officers has served as a director or member of the compensation committee (or other committee performing similar functions) of any other entity of which an executive officer served on our Board or our Compensation Committee.

Compensation Committee Report

During the last fiscal year, and this year in preparation for the filing of this proxy statement with the SEC, the Compensation Committee:

• reviewed and discussed the disclosure set forth under the heading “Compensation Discussion and Analysis” with management; and

• based on the reviews and discussions referred to above, recommended to the Board of Directors that the disclosure set forth under the heading “Compensation Discussion and Analysis” be included in this proxy statement and in C&J Energy Services, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

Respectfully submitted by the Compensation Committee of the Board of C&J Energy Services, Inc.

H. H. Wommack, III (Chairman)

Darren M. Friedman

James P. Benson

Michael Roemer

C. James Stewart III

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, 2011.

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)	6,797,089	$10.94	722,618
Equity compensation plans not approved by security holders	-	-	-
Total	6,797,089	$10.94	722,618

⁽¹⁾  Consists of (i) 1,819,818 non-qualified stock options issued and outstanding under the C&J Energy Services, Inc. 2006 Stock Option Plan and (ii) 4,977,271 non-qualified stock options issued and outstanding under the C&J Energy Services,

-113-

Inc. 2010 Stock Option Plan. 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. See “Note 7 - Stock-Based Compensation” in Part II, Item 8 “Financial Statements” for additional information regarding these stock options plans.

Security Ownership of Certain Beneficial Owners and Management

The following table shows the amount of our common stock beneficially owned (unless otherwise indicated) by our directors, our Named Executive Officers, our current directors and executive officers as a group, and any stockholders with over 5% of our common stock.

Except as otherwise indicated, all information is as of February 24, 2012.

Name and Address of Beneficial Owner(1)	Aggregate Number of Shares Owned(2)	Acquirable within 60 Days(3)	Percent of Class Outstanding(4)
Lord, Abbett & Co. LLC (5)	3,440,070		6.6%
Energy Spectrum Partners IV LP(6)	3,296,549		6.4%
Passport Capital, LLC(7)	3,130,000		6.0%
Directors and Executive Officers:
Joshua E. Comstock (8)	3,391,000	1,201,656	8.7%
Randall C. McMullen, Jr. (9)	232,456	574,326	1.5%
John D. Foret	211,900	90,334	*
Bretton W. Barrier	9,100	315,830	*
Brandon D. Simmons	178,500	90,334	*
William D. Driver	0	135,834	*
J. P. “Pat” Winstead	35,000	90,334	*
Theodore R. Moore	0	13,334	*
Darren M. Friedman	0	3,667	*
James P. Benson	0	3,667	*
Michael Roemer	0	3,667	*
H. H. Wommack, III	0	3,667	*
C. James Stewart III	0	3,667	*
Executive Officers and Directors as Group (13 persons)	4,057,956	2,530,317	12.1%

* Represents less than 1% of the outstanding common stock

(1) Except as otherwise indicated, the mailing address of each person or entity named in the table is C&J Energy Services, Inc., 10375 Richmond Ave., Suite 2000 Houston, TX 77042.

(2) Reflects the number of shares beneficially held by the named person as of February 24, 2012 with the exception of the amounts reported in filings on Schedule 13G, which amounts are based on holdings as of December 31, 2011, or as otherwise disclosed in such filings.

(3) Reflects the number of shares that could be purchased upon the exercise of options held by the named person as of February 24, 2012, or within 60 days after February 24, 2012.

(4) Based on total shares outstanding of 51,889,242 at February 24, 2012. Based on the number of shares owned and acquirable within 60 days at February 24, 2012 by the named person assuming no other person exercises options, with the exception of the amounts reported in filings on Schedule 13G, which amounts are based on holdings as of December 31, 2011, or as otherwise disclosed in such filings.

(5) As reported on Schedule 13G as of December 31, 2011 and filed with the SEC on February 14, 2012. The address of Lord, Abbett & Co. LLC is 90 Hudson Street, Jersey City, NJ 07302. Securities reported in this Annual Report as being beneficially owned by Lord, Abbett & Co. LLC are held on behalf of investment advisory clients, which may include investment companies registered under the Investment Company Act, employee benefit plans, pension funds or other institutional clients.

(6) As reported on Schedule 13G as of December 31, 2011 and filed with the SEC on January 30, 2012. The address of Energy Spectrum Partners IV LP is 5956 Sherry Lane, Suite 900, Dallas, TX 75225. The shares for which Energy

-114-

Spectrum Partners IV LP may be deemed to have voting and dispositive control are owned directly by Energy Spectrum Partners IV LP (“ESP IV”). Energy Spectrum Securities Corporation is the sole member of Energy Spectrum IV LLC, which is the general partner of Energy Spectrum Capital IV LP, which is the general partner of ESP IV.

(7) As reported on Schedule 13G as of December 31, 2011 and filed with the SEC on February 15, 2012. The address of Passport Capital, LLC is 30 Hotaling Place, Suite 300, San Francisco, CA 94111. The beneficial owners of common shares of Passport Capital, LLC are Passport Special Opportunities Master Fund, LP (“Fund I”); Passport Energy Master Fund SPC Ltd for and on behalf of Portfolio A – Energy (“Fund II); Blackwell Partners, LLC (“Account I”), (with respect to the shares directly owned by it; Gothic Corporation; The Duke Endowment; Gothic ERP; and Gothic HSP); Passport Plus, LLC (“Passport Plus”); Passport Capital, LLC (“Passport Capital”); and John Burbank (“Burbank”). Burbank is the sole managing member of Passport Capital which serves as investment manager to Fund I, Fund II, and Account I. As a result, each of Burbank and Passport Capital may be considered to share the power to vote or direct the vote of, and the power to dispose or direct the disposition of all shares owned of record by Fund I, Fund II, and Account I. Additionally, various other entities may be considered to share the power to vote or direct the vote of, and the power to dispose or direct the disposition of all shares, specifically Passport Plus in regards to shares beneficially held by Fund I. The information disclosed herein shall not be construed as an admission that any of Burbank, Passport Plus or Passport Capital is the beneficial owner of any of the securities listed herein.

(8) Included in the shares indicated as beneficially owned by Mr. Comstock are 1,309,000 shares owned by Mr. Comstock in his individual capacity, 966,000 shares held by a trust for the benefit of Mr. Comstock, of which Mr. Comstock serves as trustee and of which he may be deemed to be the beneficial owner, 966,000 shares held by a trust for the benefit of Rebecca A. Comstock, of which Mr. Comstock serves as co-trustee and of which he may be deemed to be the beneficial owner, 150,000 shares owned by JRC Investments, LLC, of which Mr. Comstock may be deemed to be the beneficial owner in his capacity as the sole member of JRC Investments, LLC, and 1,201,656 options owned by Mr. Comstock in his individual capacity which are exercisable within 60 days of February 24, 2012.

(9) Included in the shares indicated as beneficially owned by Mr. McMullen are 132,456 shares owned by Mr. McMullen in his individual capacity, 50,000 shares held by a trust for the benefit of Mr. McMullen, of which Mr. McMullen is the sole trustee and of which he may be deemed to be the beneficial owner, 50,000 shares held by a trust for the benefit of Tracy A. McMullen, of which Mr. McMullen is the sole trustee, and 574,326 options owned by Mr. McMullen in his individual capacity which are exercisable within 60 days of February 24, 2012.

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

Amended and Restated Stockholders’ Agreement

In December 2010, the Sponsors, we and certain of our other stockholders entered into an Amended and Restated Stockholders’ Agreement, which was amended on May 12, 2011 and July 14, 2011 (as amended, the “Amended and Restated Stockholders’ Agreement”). The following members of our management are a party to the Amended and Restated Stockholders’ Agreement: Joshua E. Comstock, John D. Foret, Randall C. McMullen, Jr., Brandon D. Simmons, William D. Driver, Bretton W. Barrier and J.P. “Pat” Winstead. The Amended and Restated Stockholders’ Agreement amends and restates the 2006 Shareholders’ Agreement. The Amended and Restated Stockholders’ Agreement, along with its amendment, are filed as exhibits to this 10-K.

Initial Public Offering

On July 28, 2011, our registration statement on Form S-1 (File No. 333-173177) relating to our IPO of 13,225,000 shares of our common stock was declared effective by the SEC. The IPO closed on August 3, 2011, at which time we issued and sold 4,300,000 shares and the selling stockholders, including the Sponsors, sold 8,925,000 shares, including 1,725,000 shares sold by the Sponsors pursuant to the full exercise of the underwriters’ option to purchase additional shares. These shares

-115-

were sold at a price to the public of $29.00 per share. We did not receive any proceeds from the sale of shares by the selling stockholders.

Acquisition of Total

We have historically and continue to purchase a significant portion of machinery and equipment from Total. Since 2010, Total has constructed almost all of our hydraulic pressuring pumps and is currently constructing the fracturing pumps on our three on-order fleets. Total has also constructed all of our coiled tubing and pressure pumping equipment since 2004. For the period from January 1, 2011 through April 28, 2011 (the date of our acquisition of Total), fixed asset purchases from Total were $26.2 million, and at April 28, 2011, deposits with Total on equipment to be purchased were $2.2 million and amounts payable to Total were $0.4 million and included in accounts payable.

On April 28, 2011, we acquired Total for an aggregate purchase price of approximately $33.0 million, including $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, we acquired net working capital assets with an estimated value of approximately $6.9 million, including $5.4 million in cash and cash equivalents.

At the time of the Total acquisition, our Chief Executive Officer, Joshua E. Comstock, owned 12% of Total’s outstanding equity and served on its board of directors until March 2011. HKW Capital Partners, II, L.P. and HKW Capital Partners II – Supplemental, L.P. (collectively, “HKW II”), HKW sponsored funds, owned a controlling interest in Total. Prior to and at the time of the Total acquisition, Michael Roemer, a member of our Board, was serving as the chief financial officer of HKW and two of its officers sat on the board of Total. Although Mr. Roemer stepped down from his position with HKW effective January 1, 2012, he continues to be an investor in HKW II. From March 2007 through the closing date of the acquisition, Total paid management fees to HKW II in the amount of $180,000 per year. Additionally, as noted above, Total built and sold coiled tubing and hydraulic fracturing equipment to us during HWK II’s ownership.

Supplier Agreements

We purchase sand hauling services from Pinch Flatbed, Inc. (“Pinch”), pursuant to what management believes is an arms-length contractual arrangement entered into April 1, 2011. For the year ended December 31, 2011 purchases from Pinch were $5.5 million. Pinch is a wholly owned subsidiary of PSI Frac Logistics, LLC (“PSI”). During 2011 PSI was owned 50% by an unaffiliated third party and 50% by Mr. Pat Winstead, our Vice President – Sales and Marketing, and certain other members of his family. Subsequent to December 31, 2011 the ownership interest in PSI that was previously held by Mr. Winstead and certain members of his family was sold to an unaffiliated third party. We plan to continue to purchase sand hauling services from Pinch pursuant to the terms of our contractual arrangement with Pinch for the foreseeable future.

We purchase certain transportation and logistical services from Sundance Services, Inc. (“Sundance”), pursuant to what management believes is an arms-length arrangement. Sundance is a private oilfield services company owned primarily by Mr. Pat Winstead and certain other members of his family. For the year ended December 31, 2011 purchases from Sundance were $0.2 million. We plan to continue to purchase certain transportation and logistical services on a non-contractual basis in order to partially fulfill our logistical needs as such needs arise.

-116-

We purchase controls and instrumentation equipment from both Lime Instruments (“Lime”) and Supreme Electrical Services, Inc. (“Supreme”) pursuant to what management believes is an arms-length arrangement. For the year ended December 31, 2011, purchases from Supreme/Lime were approximately $0.7 million. In addition, Total has made purchases from each of Supreme and Lime in an aggregate amount of approximately $3.3 million during the year ended December 31, 2011. Subsequent to the second quarter of 2011, Supreme was wholly owned by Stewart & Sons Holding Co. (“Holding”), which in turn was wholly owned by C. James Stewart, III, a member of our Board. In the second quarter of 2011, Holding reorganized its subsidiaries such that it owns 50% of Supreme with Mr. Stewart’s son owning 40% and unaffiliated third parties owning the remaining 10%. Lime was formed in connection with that reorganization and, from that point forward, Lime replaced Supreme as the entity with which we transacted. Holding also owns 50% of Lime with Mr. Stewart’s son owning 40% and unaffiliated third parties owning the remaining 10%. Mr. Stewart serves as chairman of each of Lime and Supreme, and his son serves as president of both entities. We, through both C&J and Total, plan to continue our purchasing relationship on a non-contractual basis with Lime/Supreme for the foreseeable future.

Additionally, we purchase blenders and hydration units from Surefire Industries, USA (“Surefire”) pursuant to what management believes is an arms-length arrangement. For the year ended December 31, 2011, purchases from Surefire were approximately $5.1 million. Surefire is a 50/50 Joint Venture Company, 25% of which is owned by Holding, 25% of which is owned by Mr. Stewart’s son and the remaining 50% owned by Surefire Industries of Canada, an unaffiliated third party. Mr. Stewart is the chairman of Surefire and his son serves as president. We plan to continue our purchasing relationship with Surefire for the foreseeable future.

Registration Rights Agreement

In December 2010, in connection with the closing of the 2010 Private Placement, we entered into a registration rights agreement among us, certain of our stockholders and FBR Capital Markets & Co., or the Registration Rights Agreement. Under the Registration Rights Agreement, we agreed, at our expense, to file with the SEC, in no event later than March 31, 2011, a shelf registration statement registering for resale the 28,768,000 shares of our common stock sold in the 2010 Private Placement plus any additional shares of common stock issued in respect thereof whether by stock dividend, stock distribution, stock split, or otherwise, and to cause such registration statement to be declared effective by the SEC as soon as practicable but in any event within 180 days after the initial filing of such registration statement. Under the Registration Rights Agreement we were permitted to delay effectiveness for 60 days following the closing of our IPO. On September 30, 2011, our registration statement on Form S-1 (File No. 333-173188) relating to our shelf registration statement was declared effective by the SEC.

We are required to use our commercially reasonable efforts, subject to certain blackout periods, to continuously maintain the effectiveness of the shelf registration statement under the Securities Act until the first to occur of:

• the sale of all of the shares of common stock covered by the shelf registration statement in accordance with the intended distribution of such common stock;

• none of the shares of common stock with rights under the registration rights agreement remain outstanding; or

-117-

• the first anniversary of the initial effective date of the shelf registration statement, subject to certain conditions and extension periods, as applicable.

Other Transactions

JRC Investments, LLC, of which Mr. Comstock is the sole member, owns a personal aircraft that Mr. Comstock uses for personal travel and business travel. When Mr. Comstock uses the aircraft for business travel, we partially reimburse Mr. Comstock for certain costs associated with the business travel. For the year ended December 31, 2011, we paid $199,286 to reimburse Mr. Comstock for business travel on his personal aircraft. These reimbursement costs and third party payments are included in selling, general and administrative expenses in our consolidated statement of operations. We believe that the costs and expenses associated with these reimbursements were substantially less than what Mr. Comstock could have obtained in an arm’s-length transaction and substantially less than the actual costs of such flights to Mr. Comstock.

Each of Mr. Comstock and Mr. Roemer is an investor in HKW Capital Partners III, L.P. (“HKW III”), an HKW sponsored fund. Mr. Comstock, as a limited partner of HKW III, has committed $2.0 million to HKW III to date and Mr. Roemer, as a limited partner of the general partner of HKW III, has committed $1.6 million to HKW III to date. As previously noted, Mr. Roemer served as chief financial officer of HKW III’s sponsor, HKW, until January 1, 2012.

Policies and Procedures

We review all relationships and transactions in which we, our control persons and our directors and executive officers or their immediate family members are participants to determine whether such persons have a direct or indirect material interest. Pursuant to our Related Persons Transactions Policy adopted on July 14, 2011, our General Counsel is primarily responsible for developing and implementing procedures and controls to obtain information from the directors and executive officers with respect to related person transactions and for subsequently determining, based on the facts and circumstances disclosed to them, whether we or a related person has a direct or indirect material interest in the transaction.

On July 14, 2011, we adopted a Code of Business Conduct and Ethics, which discourages all conflicts of interest and provide guidance with respect to conflicts of interest. Under the Code of Business Conduct and Ethics, conflicts of interest occur when private or family interests interfere in any way, or even appear to interfere, with our interests. Our restrictions on conflicts of interest under the Code of Business Conduct and Ethics include related person transactions.

We have multiple processes for reporting conflicts of interests, including related person transactions. Under our Code of Business Conduct and Ethics, all employees are required to report any actual or apparent conflicts of interest, or potential conflicts of interest, to their supervisors. This information is then reviewed by our Audit Committee, our Board or our independent registered public accounting firm, as deemed necessary, and discussed with management. As part of this review, the following factors are generally considered:

• the nature of the related person’s interest in the transaction;

• material terms of the transaction, including, without limitation, the amount and type of transaction;

• the importance of the transaction to the related person;

-118-

• the importance of the transaction to us;

• whether the transaction would impair the judgment of a director or executive officer to act in the best interest of our company; and

• any other matters deemed appropriate with respect to the particular transaction.

Ultimately, all such transactions will be required to be approved or ratified by our Board in accordance with our planned Related Persons Transactions Policy. Any member of our Board who is a related person with respect to a transaction will be recused from the review of the transaction.

In addition, we annually distribute a questionnaire to our executive officers and members of our Board requesting certain information regarding, among other things, their immediate family members, employment and beneficial ownership interests. This information is then reviewed for any conflicts of interest under the planned Code of Business Conduct and Ethics. At the completion of the annual audit, our Audit Committee and our independent registered public accounting firm review with management, insider and related person transactions and potential conflicts of interest.

Historically, related party transactions were reviewed by our Board without any formal policies or procedures being in place. We believe the more detailed process for identifying, reviewing and assessing related party transactions required by our recently adopted Code of Business Conduct and Ethics is a preferable process for dealing with related party transactions as a public company going forward. Because we adopted our Code of Business Conduct and Ethics on July 14, 2011, all of the related party transactions described above that occurred prior to July 14, 2011 were approved under our previous practices for assessing related party transactions.

Director Independence

Please see Part III, Item 10 “Directors, Executive Officers and Corporate Governance” of this report for a discussion of director independence matters.

Item 14. Principal Accounting Fees and Services

The firm of UHY LLP (“UHY”) acts as our principal independent registered public accounting firm. UHY personnel work under the direct control of UHY partners and are leased from wholly-owned subsidiaries of UHY Advisors, Inc. in an alternative practice structure.

Set forth below is a summary of fees paid to UHY, who has served as our independent registered public accounting firm since December 17, 2010, for services related to the fiscal years ended December 31, 2011 and December 31, 2010. In determining the independence of UHY, the Audit Committee considered whether the provision of non-audit services is compatible with maintaining UHY’s independence.

	Years Ended December 31,
	2011		2010
Audit fees	$	397,433	$	89,739
Audit related fees		75,497		104,384
Tax fees		6,207		13,950
Total	$	479,137	$	208,073

-119-

Audit fees consisted of amounts incurred for services performed in association with the annual financial statement audit (including required quarterly reviews), and other procedures required to be performed by the independent registered public accounting firm to be able to form an opinion on our consolidated financial statements. Other procedures included consultations relating to the audit or quarterly reviews, and services performed in connection with SEC registration statements, periodic reports and other documents filed with the SEC or other documents issued in connection with securities. Also included in audit fees are amounts incurred for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements or that are traditionally performed by the independent registered public accounting firm, consisting primarily of consultation related to management’s response to an SEC comment letter.Audit related fees consist of amounts incurred for due diligence services performed.Tax fees in 2011 and 2010 consisted of tax preparation and compliance services.

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

Our Consolidated Financial Statements are included under Part II, Item 8 of this Form 10-K. For a listing of these statements and accompanying footnotes, see “Index to Consolidated Financial Statements” beginning on page 55 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, dated February 27, 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)
10.1+	C&J Energy Services, Inc. 2006 Stock Option Plan, adopted by the Board of Directors and approved by the Shareholders on October 16, 2006 (incorporated herein by reference to Exhibit 10.1 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))

-120-

Exhibit No.	Description of Exhibit.
10.2+	Amendment to the C&J Energy Services, Inc. 2006 Stock Option Plan, dated December 23, 2010 (incorporated herein by reference to Exhibit 10.2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
10.3+	C&J Energy Services, Inc. 2010 Stock Option Plan, adopted by the Board of Directors and approved by the Shareholders on December 15, 2010 (incorporated herein by reference to Exhibit 10.3 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333- 173177)
10.4	Master Operating Lease dated July 14, 2010, between BB&T Equipment Finance Corporation, the C&J Spec- Rent Services, Inc. and C&J Energy Services, Inc., as amended, supplemented and modified from time to time, and the related Equipment Schedules (as defined therein) (incorporated herein by reference to Exhibit 10.4 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333- 173177))
10.5	Master Operating Lease Agreement dated as of July 21, 2010, between AIG Commercial Equipment Finance, Inc., and C&J Spec-Rent Services, Inc. and C&J Energy Services, Inc., as amended, supplemented and modified from time to time, and the related Equipment Schedules (as defined therein) (incorporated herein by reference to Exhibit 10.5 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
10.6	Rider 1 dated as of July 21, 2010 to Master Operating Lease Agreement dated as of July 21, 2010, between AIG Commercial Equipment Finance, Inc., and C&J Spec-Rent Services, Inc. and C&J Energy Services, Inc., as amended, supplemented and modified from time to time, and the related Equipment Schedules (as defined in the Master Operating Lease Agreement) (incorporated herein by reference to Exhibit 10.6 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
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 the 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 the 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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)

-121-

Exhibit No.	Description of Exhibit.
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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.11+	Joshua E. Comstock Non-Statutory Stock Option Agreement, dated December 23, 2010 (incorporated herein by reference to Exhibit 10.11 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.12+	Randall C. McMullen, Jr. Non-Statutory Stock Option Agreement, dated December 23, 2010 (incorporated herein by reference to Exhibit 10.12 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.13+	Bretton W. Barrier Non-Statutory Stock Option Agreement, dated December 23, 2010 (incorporated herein by reference to Exhibit 10.13 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.14+	Theodore R. Moore Non-Statutory Stock Option Agreement, dated February 1, 2011 (incorporated herein by reference to Exhibit 10.14 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.15	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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
10.16	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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333- 173177))
10.18	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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))

-122-

Exhibit No.	Description of Exhibit.
10.19	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))
*16.1	Letter from Flackman Goodman & Proctor, P.A., dated February 28, 2012
*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

-123-

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 28^th day of February, 2012.

C&J Energy Services, Inc.
By:	/s/ Randall C. McMullen, Jr.
	Randall C. McMullen,
	Jr. Executive Vice President,
	Chief Financial Officer and Treasurer
	(Duly Authorized Officer and 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 28, 2012
	Joshua E. Comstock, Chief Executive Officer
By:	/s/ Randall C. McMullen, Jr.	February 28, 2012
	Randall C. McMullen, Jr., Chief Financial Officer
By:	/s/ Mark C. Cashiola	February 28, 2012
	Mark C. Cashiola, Principal Accounting Officer
By:	/s/ James P. Benson	February 28, 2012
	James P. Benson, Director
By:	/s/ Darren M. Friedman	February 28, 2012
	Darren M. Friedman, Director
By:	/s/ Michael Roemer	February 28, 2012
	Michael Roemer, Director
By:	/s/ C. James Stewart III	February 28, 2012
	C. James Stewart III, Director
By:	/s/ H. H. “Tripp” Wommack, III	February 28, 2012
	H. H. “Tripp” Wommack, III, Director

-124-

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, dated February27, 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)
10.1+	C&J Energy Services, Inc. 2006 Stock Option Plan, adopted by the Board of Directors and approved by the Shareholders on October 16, 2006 (incorporated herein by reference to Exhibit 10.1 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
10.2+	Amendment to the C&J Energy Services, Inc. 2006 Stock Option Plan, dated December 23, 2010 (incorporated herein by reference to Exhibit 10.2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
10.3+	C&J Energy Services, Inc. 2010 Stock Option Plan, adopted by the Board of Directors and approved by the Shareholders on December 15, 2010 (incorporated herein by reference to Exhibit 10.3 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333- 173177)
10.4	Master Operating Lease dated July 14, 2010, between BB&T Equipment Finance Corporation, the C&J Spec- Rent Services, Inc. and C&J Energy Services, Inc., as amended, supplemented and modified from time to time, and the related Equipment Schedules (as defined therein) (incorporated herein by reference to Exhibit 10.4 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
10.5	Master Operating Lease Agreement dated as of July 21, 2010, between AIG Commercial Equipment Finance, Inc., and C&J Spec-Rent Services, Inc. and C&J Energy Services, Inc., as amended, supplemented and modified from time to time, and the related Equipment Schedules (as defined therein) (incorporated herein by reference to Exhibit 10.5 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
10.6	Rider 1 dated as of July 21, 2010 to Master Operating Lease Agreement dated as of July 21, 2010, between AIG Commercial Equipment Finance, Inc., and C&J Spec-Rent Services, Inc. and C&J Energy Services, Inc., as amended, supplemented and modified from time to time, and the related Equipment Schedules (as defined in the Master Operating Lease Agreement) (incorporated herein by reference to Exhibit 10.6 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))

-125-

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 the 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 the 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 the 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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.11+	Joshua E. Comstock Non-Statutory Stock Option Agreement, dated December 23, 2010 (incorporated herein by reference to Exhibit 10.11 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.12+	Randall C. McMullen, Jr. Non-Statutory Stock Option Agreement, dated December 23, 2010 (incorporated herein by reference to Exhibit 10.12 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.13+	Bretton W. Barrier Non-Statutory Stock Option Agreement, dated December 23, 2010 (incorporated herein by reference to Exhibit 10.13 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.14+	Theodore R. Moore Non-Statutory Stock Option Agreement, dated February 1, 2011 (incorporated herein by reference to Exhibit 10.14 to Amendment No. 2 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177)
10.15	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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
10.16	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 the C&J Energy Services, Inc’s Registration Statement on Form S-1/A, dated May 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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))

-126-

10.18	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 the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
10.19	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))
*16.1	Letter from Flackman Goodman & Proctor, P.A., dated February 28, 2012
*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

-127-