As filed with the Securities and Exchange Commission on September 16, 2011

Registration No. 333-173188

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 6

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

C&J Energy Services, Inc.

(Exact name of registrant as specified in its charter)

 

10375 Richmond Avenue, Suite 2000

Houston, Texas 77042

(713) 260-9900

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

Theodore R. Moore

Vice President-General Counsel

C&J Energy Services, Inc.

10375 Richmond Avenue, Suite 2000

Houston, Texas 77042

(713) 260-9900

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

 

 

Copies to:

 

 

 

 

 

Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.

 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box.  þ

 

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

 

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

 

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

 

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. (Check one):

(Do not check if a smaller reporting company)

 

 

 

 

CALCULATION OF REGISTRATION FEE

 

 

 

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

Subject to Completion, Dated September 16, 2011

 

PRELIMINARY PROSPECTUS

 

 

C&J Energy Services, Inc.

 

38,463,074 shares

Common Stock

 

 

 

 

The selling stockholders are offering 38,463,074 shares of our common stock, which the selling stockholders acquired pursuant to a private placement between us and the selling stockholders. All of these shares of common stock are being sold by the selling stockholders named in this prospectus, or their respective transferees, pledgees, donees or successors-in-interest. The selling stockholders will receive all proceeds from the sale of the shares of our common stock being offered in this prospectus. We will not receive any proceeds from the sale of shares by the selling stockholders.

 

Our common stock is traded on the New York Stock Exchange under the symbol “CJES.”

 

The selling stockholders may sell the shares of common stock being offered by them from time to time on the New York Stock Exchange, in market transactions, in negotiated transactions or otherwise, and at prices and terms that will be determined by the then prevailing market price for the shares of common stock or at negotiated prices directly or through a broker or brokers, who may act as agent or as principal or by a combination of such methods of sale. For additional information on the methods of sale, you should refer to the section entitled “Plan of Distribution” beginning on page 107 of this prospectus.

 

Investing in our common stock involves risks. Please read “Risk Factors” beginning on page 5 of this prospectus.

 

 

 

 

The Securities and Exchange Commission and state securities regulators have not approved or disapproved of these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

 

 

Prospectus dated          , 2011.

 

TABLE OF CONTENTS

 

 

 

 

 

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by or on behalf of us or to which we have referred you. Neither we nor the selling stockholders have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. The selling stockholders are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of common stock.

 

We have not taken any action to permit a public offering of the shares of common stock outside the United States or to permit the possession or distribution of this prospectus outside the United States. Persons outside the United States who come into possession of this prospectus must inform themselves about and observe any restrictions relating to the offering of the shares of common stock and the distribution of this prospectus outside the United States.

 

Industry and Market Data

 

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good-faith estimates.

 

PROSPECTUS SUMMARY

Common stock offered by the Selling Stockholders		38,463,074 shares

Common stock to be outstanding after this offering(1)		51,886,574 shares

Use of Proceeds		We will not receive any proceeds from the sale of shares by the selling stockholders.
Risk Factors		Investing in our common stock involves a high degree of risk. For a discussion of factors you should consider before making an investment, please read “Risk Factors” beginning on page 5 of this prospectus.
New York Stock Exchange Symbol		CJES

	(1)	The number of outstanding shares as of September 14, 2011 excludes (i) 6,742,089 shares of common stock issuable upon exercise of options currently outstanding, of which 1,838,153 currently are exercisable and (ii) an aggregate of approximately 777,618 shares of common stock reserved and available for future issuance under the C&J Energy Services, Inc. 2010 Stock Option Plan, or the 2010 Plan. For additional information regarding the 2010 Plan, please read “Executive Compensation and Other Information — Components of Executive Compensation Program — Stock Options” on page 67 of this prospectus.

	•	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.
	•	Because the oil and gas industry is cyclical, our operating results may fluctuate.
	•	Delays in delivery of our new fracturing fleets or future orders of specialized equipment from suppliers could harm our business, results of operations and financial condition.
	•	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.
	•	There is potential for excess capacity in our industry.
	•	Federal legislation 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 our support services.
	•	We participate in a capital-intensive industry. We may not be able to finance future growth of our operations or future acquisitions.

 

You should carefully consider each of the following risk factors and all of the other information set forth in this prospectus and the documents and other information incorporated by reference herein before deciding to invest in our common stock. 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. If that occurs, the value of our common stock could decline and you could lose some or all of your investment.

 

Risks Relating to Our Business

 

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

 

We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas in the United States. If these expenditures decline, 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 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. As of September 14, 2011, the Henry Hub spot price for natural gas was $4.04 per mcf. 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. For example, in 2009, due to fluctuations in our operating results caused largely by the volatility of commodity prices, we faced potential payment and covenant defaults under our then-existing subordinated term loan agreement. In connection with such potential defaults, we obtained a waiver from our lenders to extend the maturity date and amend certain payment terms and maintenance covenants under such facility. If our operating results are adversely impacted by actual or anticipated changes in oil and natural gas prices, or for any other reason, then we may be in default under our debt arrangements and be required to seek a waiver from our lenders in the future, and such measures may not be successful.

 

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

 

Currently, the demand for hydraulic fracturing services exceeds the availability of fracturing equipment and crews across the industry and in our operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional, as opposed to conventional, oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages has further amplified this equipment and crew shortage. 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 on order. If demand for fracturing services decreases or the supply of fracturing equipment and crews continues to increase, then 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.

 

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 6, 7 and 8. We expect to take delivery of Fleet 6 in the fourth quarter of 2011, Fleet 7 in the first half of 2012 and Fleet 8 in the second half of 2012. The delivery of Fleets 6, 7 and 8, or any other fracturing fleets we may order in the future, could be materially delayed or not delivered at all. Total is constructing our hydraulic fracturing pumps for all three of our on-order fleets. 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, 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 2008, 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 legislation 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 our support services.

 

The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or 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. The United States Environmental Protection Agency, or EPA, has recently 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. 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. 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, which has not passed, has been introduced before Congress in the last few sessions to provide for federal regulation of hydraulic fracturing and to require 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.

 

Our top five customers accounted for approximately 81.0%, 67.4% and 61.1% of our revenue for the years ended December 31, 2010, 2009 and 2008, respectively. Our top ten customers represented approximately 90.2%, 90.6% and 79.9% of our revenue for the years ended December 31, 2010, 2009 and 2008, respectively. For the six months ended June 30, 2011, our top five customers accounted for 84.5% of our revenues and our top ten customers accounted for 94.1% of our revenues. 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.

 

A significant amount of our revenue is currently derived from term contracts. For the three and six months ended June 30, 2011, we derived 67.2% and 61.6%, respectively, of our total revenues from our term contracts. The terms of these contracts range from one to three years. Once these contracts expire, we may not be able to extend the 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, 2010, our Adjusted EBITDA increased $62.7 million from $19.9 million to $82.6 million, our revenues increased $181.8 million from $62.4 million to $244.2 million, and our net income increased $31.2 million from $1.1 million to $32.3 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 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:

 

 

 

 

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

acquisition, including our acquisition of Total, 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.

 

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 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. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Description of Our Indebtedness” beginning on page 35 of this prospectus for additional information regarding our credit facility.

 

Energy Spectrum and Citigroup/Stepstone will continue to have significant influence over us, including influence over decisions that require stockholder approval, which could limit your ability to influence the outcome of key transactions, including a change in control.

 

Energy Spectrum Partners IV LP, whom we refer to in this prospectus as Energy Spectrum, holds approximately 6.4% of our outstanding common stock, and StepStone Capital Partners II Onshore, L.P., StepStone Capital Partners II Cayman Holdings, L.P., 2006 Co-Investment Portfolio, L.P. and Citigroup Capital Partners II Employee Master Fund, L.P., whom we collectively refer to in this prospectus as Citigroup/StepStone hold approximately 7.6% of our outstanding common stock. Each of Citigroup/StepStone and Energy Spectrum, collectively referred to in this prospectus as our Sponsors, currently has one director on our board of directors. As a result, our Sponsors have significant influence over our decisions to enter into any corporate transaction regardless of whether others believe that the transaction is in our best interests. Please read “Certain Relationships and Related Party Transactions — Amended and Restated Stockholders’ Agreement” beginning on page 78 of this prospectus.

As long as our Sponsors continue to hold a large portion of our outstanding common stock, they will have the ability to influence the vote in any election of directors and over decisions that require stockholder approval. In addition, the concentration of ownership may have the effect of delaying, preventing or deterring a change in control of our company, could deprive stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company and might ultimately affect the market price of our common stock.

 

Our Sponsors are also in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. Our Sponsors may also pursue acquisition opportunities that are complementary to our business, and, as a result, those acquisition opportunities may not be available to us.

 

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.

 

Prior to our IPO, as a privately held company, we were not required to comply with Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, and were therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Following the effectiveness of our IPO registration statement, we became a public company and are, therefore, 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 the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, including information technology, implement additional financial and management controls, reporting systems and procedures and hire 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 New York Stock Exchange, or 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:

 

 

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 greenhouse gases 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 greenhouse gases, or 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 climate changes. Based on these findings, the EPA has begun to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act, or the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which will require that certain large stationary sources obtain permits for their emissions of greenhouse gases, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

 

In addition to the EPA, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and more than one-third of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.

 

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 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. Please read “Business — Environmental Matters” beginning on page 49 of this prospectus for a more detailed description of our climate-change related risks.

 

We are subject to extensive and costly environmental, health and safety laws, rules 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 or otherwise relating to protection of the environment or human health and safety. 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 hazardous waste. The generation, handling, transportation, and disposal of these fluids, substances, and waste are regulated by a number of laws, including the Resource Recovery and Conservation Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Water Act; the Safe Drinking Water Act; 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 as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Environmental laws and regulations have changed in the past, and they are likely to change in the future. If existing regulatory requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.

 

Any failure by us to comply with applicable environmental, health and safety laws, rules and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the:

 

 

The effect of environmental laws and regulations on our business is discussed in greater detail under “Business — Environmental Matters” beginning on page 49 of this prospectus.

 

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 United States Department of Transportation, or 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.

 

Our senior executive officers and several of our directors may not be able to organize and effectively manage a publicly traded company, which could adversely affect our business, financial condition and results of operations.

 

We completed our IPO on August 3, 2011, and became a publicly traded company. Some of our senior executive officers and directors have not previously organized or managed a publicly traded company, and our senior executive officers and directors may not be successful in doing so. The demands of organizing and managing a publicly traded company are much greater as compared to a private company and some of our senior executive officers and directors may not be able to meet those increased demands. Failure to organize and effectively manage us could adversely affect our business, financial condition and results of operations.

 

Risks Related to Our Common Stock

 

We do not anticipate paying any dividends on our common stock in the foreseeable future.

 

For the foreseeable future, we intend to retain earnings to grow our business. Payments of dividends, if any, will be at the discretion of our board of directors and will depend on many factors, including general economic and business conditions, our strategic plans, our financial results and condition, legal requirements and other factors as our board of directors deems relevant. Our credit facility restricts our ability to pay cash dividends on our common stock and we may also enter into credit agreements or borrowing arrangements in the future that will restrict our ability to declare or pay cash dividends on our common stock.

 

We will incur increased costs as a result of being a public company.

 

Prior to our IPO, as a privately held company, we were not responsible for complying with the corporate governance and financial reporting practices and policies required of a publicly traded company. We completed our IPO on August 3, 2011, and became a publicly traded company. As a public company with listed equity securities, we are now required to comply with various state and federal laws, regulations and requirements applicable to public companies as well as certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, the rules and regulations of the SEC and the requirements of the NYSE, none of which we were required to comply as a private company. Compliance with these laws, regulations and requirements occupies a significant amount of time of our board of directors and management and significantly increased our costs and expenses. We need to:

 

 

 

In addition, we also expect that being a public company subject to these rules and regulations will 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 September 14, 2011, we had 51,886,574 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 amended and restated certificate of incorporation and amended and restated 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, once our Sponsors’ beneficial ownership percentage dropped below 25% of the outstanding shares of common stock in our IPO, we opted to be governed by Section 203 of the Delaware General Corporation Law, or DGCL. These provisions may also discourage acquisition proposals or delay or prevent a change in control, which could harm our stock price. Please read “Description of Capital Stock — Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law” beginning on page 98 of this prospectus.

 

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

 

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

 

Various statements contained in this prospectus and the documents and other information incorporated by reference herein, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. These forward-looking statements may include projections and estimates concerning the timing and success of specific projects, our future revenues, income and capital spending and our strategy. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this prospectus and the documents and other information incorporated by reference herein speak only as of the date of such document; we disclaim any obligation to update these statements unless required by law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These and other important factors, including those discussed under “Risk Factors” beginning on page 5 of this prospectus and in our Quarterly Report on Form 10-Q for the period ended June 30, 2011, which is incorporated by reference herein and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 20 of this prospectus and in our Quarterly Report on Form 10-Q for the period ended June 30, 2011, which is incorporated by reference herein, may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. These risks, contingencies and uncertainties include, but are not limited to, the following:

 

 

 

 

We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders.

 

For the foreseeable future, we intend to retain earnings to grow our business. Payments of dividends, if any, will be at the discretion of our board of directors and will depend on many factors, including general economic and business conditions, our strategic plans, our financial results and condition, legal requirements and other factors that our board of directors deems relevant. Our credit facility restricts our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that will restrict our ability to declare or pay cash dividends on our common stock. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Description of Our Indebtedness” beginning on page 35 of this prospectus.

 

The following table presents our summary historical financial data for the periods and as of the dates indicated. The selected consolidated statement of operations data and statement of cash flows data for the years ended December 31, 2008, 2009 and 2010 and the selected consolidated balance sheet data as of December 31, 2009 and 2010 are derived from our audited consolidated financial statements and the notes thereto included elsewhere in this prospectus. The selected consolidated statement of operations data and statement of cash flows data for the periods ended December 31, 2007 and 2006 and October 16, 2006 and the selected consolidated balance sheet data as of December 31, 2008, 2007 and 2006 and October 16, 2006 were audited by Flackman Goodman & Potter, P.A., or Flackman, an accounting firm not registered with the PCAOB, and are considered “unaudited” for purposes of the registration statement of which this prospectus is a part. The unaudited consolidated statement of operations data and unaudited statement of cash flows data for the six months ended June 30, 2011 and 2010 and the selected unaudited consolidated balance sheet data as of June 30, 2011 are derived from our unaudited consolidated financial statements and the notes thereto included elsewhere in this prospectus. The unaudited financial data has, in our opinion, been prepared on a basis consistent with the audited consolidated financial statements and notes thereto and includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of this information.

 

Historical results are not necessarily indicative of the results we expect in future periods. The information presented below should be read in conjunction with, and is qualified in its entirety by reference to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 20 of this prospectus and our consolidated financial statements and the notes thereto included elsewhere in this prospectus.

 

 

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Selected Consolidated Financial Data” beginning on page 18 of this prospectus and our financial statements and related notes appearing elsewhere in this prospectus. This discussion contains forward-looking statements based on our current expectations, estimates and projections about our operations and the industry in which we operate. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this prospectus under “Cautionary Note Regarding Forward-Looking Statements” on page 16 of this prospectus and “Risk Factors” beginning on page 5 of this prospectus. We assume no obligation to update any of these forward-looking statements.

 

Overview

 

We are a rapidly growing independent provider of premium hydraulic fracturing and coiled tubing services with a focus on complex, technically demanding well completions. We have historically operated in what we believe to be some of the most geologically challenging basins in South Texas, East Texas/North Louisiana and Western Oklahoma. 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.

 

We are a Delaware corporation. 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 the SEC and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the SEC. Information available on or through our website is not a part of or incorporated into this prospectus or any other report that we file with the SEC.

 

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.

 

We have entered into term contracts with EOG Resources (executed April 2010), Penn Virginia (executed May 2010), Anadarko Petroleum (executed August 2010), EXCO Resources (executed August 2010), and Plains Exploration (executed March 2011) for the provision of hydraulic fracturing services. We began service under the Penn Virginia, EOG Resources, Anadarko Petroleum, EXCO Resources and Plains Exploration contracts in July 2010, August 2010, February 2011, April 2011 and August 2011, respectively. Our existing hydraulic fracturing fleets (Fleets 1, 2, 3, 4 and 5) are dedicated through mid-2012, mid-2012, early 2013, mid-2014 and mid-2013, respectively, to producers operating in the Eagle Ford, Haynesville and Granite Wash basins. We are scheduled to take delivery of Fleets 6, 7 and 8 in the fourth quarter of 2011, the first half of 2012 and the second half of 2012, respectively. We are seeking to deploy each of these new fleets under term contracts similar to our existing term contracts.

 

Our revenues are derived primarily from three sources:

 

 

 

 

Hydraulic Fracturing.  Approximately 80% of our revenues for the six months ended June 30, 2011 were derived from hydraulic fracturing services. Our term contracts generally range from one year to three years. Under the term contacts, 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 utilize more than the specified contract minimums, we will be paid a pre-agreed amount for the provision of such additional services. Our term contracts restrict the ability of the customer to terminate or require our customers to pay us a lump-sum early termination fee, generally representing all or a significant portion of the remaining economic value of the contracts to us.

 

Although our term contracts provide us some visibility on anticipated future minimum asset utilization, our term contracts 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:

 

 

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 and chemicals and proppant materials consumed. 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 hydraulic fracturing fleets, we also have the flexibility to pursue spot market projects. 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. We may also charge fees for set up 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 and we charge our customers a fee for materials consumed in the process, or we charge our customers a handling fee for 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. 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 provided in the spot market at prevailing prices per hour. We may also charge fees for set up and mobilization of equipment depending on the job. The set-up 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.  Our equipment manufacturing business constructs equipment primarily for the energy services industry, including hydraulic fracturing pumps, coiled tubing units, pressure pumping units and other equipment. This business also provides equipment repair services and oilfield parts and supplies to the energy services industry.

 

How We Manage Costs and Maintain Our Equipment

 

The principal expenses involved in conducting our business are product and material costs, the costs of acquiring, maintaining and repairing our equipment, labor expenses and fuel costs. Additionally, we incur freight costs to deliver and stage our hydraulic fracturing fleets to the worksite. We maintain and repair all equipment we use in our operations. We primarily purchase our equipment, including engines, transmissions, radiators, motors and pumps, from third-party vendors. Our acquisition of Total in April 2011 has provided us with greater control over the costs of, access to, and delivery of equipment. Total has historically been one of our largest suppliers of machinery and equipment and is currently constructing the hydraulic fracturing pumps for all three of our on-order fleets. We believe the acquisition of Total provides several strategic advantages, including a significant reduction in our exposure to third-party supply chain constraints, shorter cycle times for the delivery of new equipment and replacement parts, a reduction in and greater control of the cost of new equipment, and enhanced operational control of our service offering. Furthermore, the acquisition of Total is expected to help minimize downtime by enhancing our capabilities for maintenance and repair of our hydraulic fracturing equipment.

 

Depreciation costs represented approximately 4.0% of our revenues for the year ended December 31, 2010 and 2.5% of our revenues for the six months ended June 30, 2011. Direct labor costs represented approximately 10.7% of our revenues for the year ended December 31, 2010 and 8.7% of our revenues for the six months ended June 30, 2011. Other costs, including proppant, chemical and freight costs, represented approximately 34.7% of our revenues for the year ended December 31, 2010 and 33.2% of our revenues for the six months ended June 30, 2011. We also incur significant fuel costs in connection with the operation of our hydraulic fracturing fleets and the transportation of our equipment and products.

 

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. During the three months ended June 30, 2011, we completed 856 fracturing stages, generated average revenue per fracturing stage of $175,888 and averaged monthly revenue per unit of horsepower of $371. During the first quarter of 2011, we completed 633 fracturing stages, generated average revenue per fracturing stage of $165,717 and averaged monthly revenue per unit of horsepower of $383.

Additionally, our hydraulic fracturing fleets were nearly 100% utilized during both the first and second quarters of the year, based on available working days per month, which excludes scheduled maintenance days. During the three months ended June 30, 2011, we completed 819 coiled tubing jobs compared to 638 for the first quarter of 2011.

 

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. Our repair and maintenance costs represented approximately 6.8% and 6.6% of our revenues for the six months ended June 30, 2011 and 2010, respectively.

 

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.

 

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 hydraulic fracturing market. 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 “Risk Factors” beginning on page 5 of this prospectus, for additional information about the risks we face.

 

Equipment Supply.  The overall number of hydraulic fracturing 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 6, 7 and 8, in the fourth quarter of 2011, in the first half of 2012 and in the second half of 2012, respectively. 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 new on-order hydraulic fracturing equipment, has provided us with added monitoring capabilities and control over access to, and delivery of new fracturing equipment.

 

Hydraulic Fracturing Legislation and Regulation.  Legislation has been introduced before Congress in the last few sessions to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Although the federal legislation did

not pass, if similar federal legislation is introduced and becomes law in the future, the legislation could establish an additional level of regulation that could lead to operational delays or increased operating costs. The federal Environmental Protection Agency (“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 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 new five-year $200.0 million senior secured revolving credit facility, which increased the amount of funds we are permitted to borrow by $48.3 million and increased the amount of borrowings we can incur in a given fiscal year for capital expenditures by $60.0 million. In addition, our cash flows from operations have continued to increase dramatically, with cash flows from operations during the six months ended June 30, 2011 increasing by $47.9 million from the same period in 2010. We believe that 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 at least 2012.

 

Recent Developments

 

Initial Public Offering.  On July 28, 2011, our registration statement on Form S-1 (File No. 333-173177) relating to the 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 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, at a price to the public of $29.00 per share. We received cash proceeds of approximately $116.0 million from this transaction, net of underwriting discounts and commissions. As of September 14, 2011, we had incurred costs of approximately $3.4 million related to the offering. We did not receive any proceeds from the sale of shares by the selling stockholders.

 

Acquisition of Total E&S, Inc.  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. Since 2010, Total has constructed almost all of our hydraulic fracturing pumps and is currently constructing the hydraulic fracturing pumps for all three of our on-order fleets. Total has also constructed all of our coiled tubing and pressure pumping equipment since 2004. The aggregate purchase price of the acquisition of approximately $33.0 million included $23.0 million in cash to the sellers and $10.0 million in

repayment of the outstanding debt and accrued interest of Total. In exchange for the consideration, we acquired net working capital assets with an estimated value of approximately $6.9 million, including $5.4 million in cash and cash equivalents. We funded $25.0 million of the purchase price and debt repayment with borrowings under our credit facility and funded the remainder with cash on hand. Total is an Indiana corporation and is located in Granbury, Texas.

 

Following our acquisition of Total, we acquired approximately 10 acres of property adjacent to Total’s current facility and began construction of an approximately 36,000 square foot manufacturing facility. We currently expect our new facility to be operational in early 2012. The total cost of construction of the facility is expected to be approximately $1.6 million. By significantly increasing Total’s manufacturing capacity, we expect to further increase its ability to service us as well as its existing and future third-party customers.

 

Outlook

 

Demand for hydraulic fracturing 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 fracturing fleets in order to capitalize on the 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:

 

 

 

 

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 in our term contracts, 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 five existing fleets and intend to do the same with our three on-order hydraulic fracturing fleets.

 

In the near term, we expect that our revenues and results of operations will be positively impacted by: (i) the addition and deployment of Fleet 2 in July 2010; (ii) the addition and deployment of Fleet 3 in January 2011; (iii) the addition and deployment of Fleet 4 in April 2011 (iv) the addition and deployment of Fleet 5 in August 2011 and (v) the acquisition of Total in April 2011. We also expect to take delivery of and deploy Fleets 6, 7 and 8 in the fourth quarter of 2011, the first half of 2012 and the second half of 2012, respectively. Each of our fleets is, or is expected to be, deployed under a term contract. We expect that our results of operations in 2011 compared to 2010 will be significantly impacted by the dramatic growth of our asset base over the last twelve months.

 

Results for the Three Months Ended June 30, 2011 Compared to the Three Months Ended June 30, 2010

 

The following table summarizes the change in our results of operations for the three months ended June 30, 2011 when compared to the three months ended June 30, 2010 (in thousands):

 

 

Revenue

 

Revenue increased $140.4 million, or 336%, to $182.2 million for the three months ended June 30, 2011 as compared to $41.8 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. Fleet 2, which was deployed in the third quarter of 2010, contributed $33.0 million of revenue in the second quarter of 2011; Fleet 3, which was deployed early in the first quarter of 2011, contributed $37.3 million of revenue in the second quarter of 2011; and Fleet 4, which was deployed early in the second quarter of 2011, contributed $28.3 million of revenue in the second quarter of 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 $4.5 million of revenue during the second quarter of 2011.

 

Cost of Sales

 

Cost of sales increased $83.0 million, or 306%, to $110.1 million for the three months ended June 30, 2011 compared to $27.1 million for the same period in 2010. As a percentage of revenue, cost of sales decreased to 60% for the three months ended June 30, 2011 from 65% for the same period in 2010 due primarily to the significant increase in revenue in the second quarter of 2011 compared to the same period in the prior year.

 

Selling, General and Administrative Expenses (SG&A)

 

SG&A increased $7.9 million, or 204%, to $11.7 million for the three months ended June 30, 2011 as compared to $3.8 million for the same period in 2010. The increase primarily related to $2.7 million in higher payroll and personnel costs associated with the continued hiring of personnel to

support our growth and $2.3 million in higher long-term and short-term incentive costs. We also incurred $1.2 million in increased SG&A costs associated with the acquisition of Total in April 2011.

 

Interest Expense

 

Interest expense decreased by $5.4 million, or 82%, to $1.2 million for the three months ended June 30, 2011 as compared to $6.6 million for the same period in 2010. This decrease was due primarily to charges of $4.8 million incurred in the second quarter of 2010 in connection with the change in fair value of our warrant liability. The warrants were exercised in December 2010. Also contributing to the decrease was $0.5 million in lower interest expense due to lower interest rates and $0.1 million in lower amortization of financing costs.

 

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 three months ended June 30, 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 $18.3 million for the three months ended June 30, 2011, at an effective rate of 35.5%, compared to a tax provision of $0.9 million for the three months ended June 30, 2010, at an effective rate of 35.3%. The increase was due to our increase in net income.

 

Results for the Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2010

 

The following table summarizes the change in our results of operations for the six months ended June 30, 2011 when compared to the six months ended June 30, 2010 (in thousands):

 

 

Revenue

 

Revenue increased $234.9 million, or 316%, to $309.4 million for the six months ended June 30, 2011 as compared to $74.4 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. Fleet 2, which was deployed in the third quarter of 2010, contributed $62.4 million of revenue in the six months ended June 30, 2011; Fleet 3, which was deployed early in the first quarter of 2011, contributed $65.5 million of revenue in the six months ended June 30, 2011; and Fleet 4, which was deployed early in the second quarter of 2011, contributed $28.3 million of revenue in the six months ended June 30, 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 $4.5 million of revenue during the first half of 2011.

 

Cost of Sales

 

Cost of sales increased $129.8 million, or 258%, to $180.1 million for the six months ended June 30, 2011 as compared to $50.3 million for the same period in 2010. As a percentage of revenue, cost of sales decreased to 58% for the six months ended June 30, 2011 from 68% for the same period in 2010 due primarily to the significant increase in our revenues from 2010 to 2011.

 

Selling, General and Administrative Expenses (SG&A)

 

SG&A increased $13.8 million, or 206%, to $20.5 million for the six months ended June 30, 2011 as compared to $6.7 million for the same period in 2010. The increase primarily related to $4.8 million in higher long-term and short-term incentive costs and $4.5 million in higher payroll and personnel costs associated with the continued hiring of personnel to support our growth. We also incurred $1.2 million in increased SG&A costs associated with the acquisition of Total and $0.5 million in increased professional fees.

 

Interest Expense

 

Interest expense decreased by $6.4 million, or 67%, to $3.2 million for the six months ended June 30, 2011 as compared to $9.6 million for the same period in 2010. This decrease was due primarily to charges of $6.3 million incurred in the six months ended June 30, 2010 in connection with the change in fair value of our warrant liability. The warrants were exercised in December 2010.

 

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 six months ended June 30, 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 $35.7 million for the six months ended June 30, 2011, at an effective rate of 36.4%, compared to a tax provision of $2.4 million for the six months ended June 30, 2010, at an effective rate of 37.3%. The increase was due to our increase in net income.

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

 

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

 

 

Revenue

 

Revenue increased $177.1 million, or 264%, to $244.2 million for the year ended December 31, 2010 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 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 compared to $9.5 million for the same period in 2009. The increase primarily relates to $4.0 million in higher long-term and short-term incentive costs and $2.3 million in higher payroll and related personnel 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 $17.4 million for the year ended December 31, 2010 compared to $4.7 million for the same period in 2009. This increase was due primarily to $10.1 million in increased charges incurred in 2010 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 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.

 

Results for the Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008

 

The following table summarizes the dollar changes for our results of operations for the year ended December 31, 2009 when compared to the year ended December 31, 2008 (in thousands):

 

 

Revenue

 

Revenue increased $4.6 million, or 7%, to $67.0 million for the year ended December 31, 2009 compared to $62.4 million for the same period in 2008. This increase was primarily due to a full year of operation of our hydraulic fracturing services and East Texas operations, which began in late 2007 and gradually ramped up throughout 2008. Partially offsetting this increase, however, were decreases in revenue from our coiled tubing and pressure pumping services, which were negatively impacted in 2009 due to a significant decline in investment by our customers in oil and gas exploration and development activities. Towards the end of 2009, we began experiencing increases in revenue across all service lines, as drilling and completion activity began to rise with higher commodity prices and growing interest in the Eagle Ford Shale resource play.

Cost of Sales

 

Cost of sales increased $11.8 million, or 28%, to $54.2 million for the year ended December 31, 2009, compared to $42.4 million for the same period in 2008. As a percentage of revenue, cost of sales increased to 81% for the year ended December 31, 2009 from 68% for the same period in 2008. The overall decline in the oil and gas industry, which began in late 2008 and continued throughout most of 2009, resulted in lower utilization of our equipment and services and, to a lesser extent, pricing pressure from our competitors.

 

Selling, General and Administrative Expenses (SG&A)

 

SG&A increased $0.6 million, or 7%, to $9.5 million for the year ended December 31, 2009 compared to $8.9 million for the same period in 2008. The increase primarily relates to $0.9 million in higher costs incurred for professional fees, property taxes and office-related costs, $0.4 million in higher payroll and related personnel costs, and $0.2 million in increased costs for other SG&A-related expenses. Partially offsetting the increase were lower costs of $0.9 million due to the elimination of our short-term incentive program for 2009.

 

Interest Expense

 

Interest expense decreased by $2.2 million, or 32%, to $4.7 million for the year ended December 31, 2009 compared to $6.9 million for the same period in 2008. A lower average effective interest rate during 2009 contributed approximately $1.9 million to the decrease and lower average outstanding debt balances contributed approximately $0.4 million to the decrease. An increase in interest expense of $0.3 million related to the initial valuation of our warrant liability partially offset the overall decrease in interest expense in 2009 compared to 2008.

 

Income Taxes

 

We recorded a tax benefit of $386,000 for the year ended December 31, 2009 at an effective rate of 13.7%, compared to a tax provision of $2.1 million at an effective rate of 65%, for the year ended December 31, 2008. The primary cause for the disparity in effective rates year over year was amortization expense on our intangible assets that is non-deductible for federal income tax purposes, and, to a lesser extent, permanent book-to-tax differences generated in 2008 in connection with real estate lease incentives.

 

Liquidity and Capital Resources

 

Our primary sources of liquidity to date have been capital contributions and borrowings from stockholders, 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 we anticipate capital expenditures will continue to increase through 2012. We have ordered three new hydraulic fracturing fleets, Fleets 6, 7 and 8, which are scheduled for delivery in the fourth quarter of 2011, the first half of 2012 and the second half of 2012, respectively. Fleet 6 has an aggregate cost of approximately $33 million, of which approximately $2.6 million had been funded as of September 14, 2011. Fleet 7 has an aggregate cost of approximately $26 million, of which approximately $1.0 million had been funded as of September 14, 2011; and Fleet 8 has an aggregate cost of approximately $26 million, of which approximately $0.6 million had been funded as of September 14, 2011. We intend to fund Fleets 6, 7 and 8 through a combination of cash flows from operations, proceeds from our IPO and borrowings under our credit facility.

 

On April 19, 2011, we entered into a five-year $200.0 million revolving credit facility with a $75 million accordion feature, 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 had no balance outstanding as of September 14, 2011.

 

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 2011 and 2012 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 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. Please read “— Description of Our Indebtedness.” 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 common equity interests 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.

 

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:

 

 

 

We continually monitor new advances in hydraulic fracturing 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. Assuming the timely delivery of Fleet 6 in the fourth quarter of 2011, we expect our total 2011 capital expenditures to be approximately $120 million, of which $88.0 million has been spent as of September 14, 2011. The remainder of capital expenditures for 2011 include the purchase of Fleet 6, three new coil tubing units, and maintenance capital expenditures.

 

Historically, we have grown through organic expansion. We plan to continue to monitor the economic environment and demand for our services and adjust our business strategy as necessary.

Financial Condition and Cash Flows

 

The following table sets forth historical cash flows information for each of the years ended December 31, 2010, 2009 and 2008 and for the six months ended June 30, 2011 and 2010 (in thousands):

 

 

Cash Provided by Operating Activities

 

Net cash provided by operating activities increased $47.9 million for the six months ended June 30, 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 decrease related to working capital changes related to accounts receivable, accounts payable and income taxes payable. Accounts receivable and accounts payable were both higher due to the increase in our activity levels. Income taxes payable were lower due to substantial payments made in June 2011 for federal income tax purposes. 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, and increased $3.4 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in operating cash flows for the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily due to an increase in net income of $34.7 million. The significant changes in working capital requirements in both periods primarily related to accounts receivable, corresponding to changes in revenues. The increase in operating cash flows for the year ended December 31, 2009 compared to the year ended December 31, 2008 was primarily due to working capital improvements, offset by lower profitability.

 

Cash Flows Used in Investing Activities

 

Net cash used in investing activities increased $82.9 million for the six months ended June 30, 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 doubled in size from two fleets at the end of 2010 to four fleets early in the second quarter of 2011. For the six months ended June 30, 2011 we spent $48.9 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, and decreased $16.4 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in cash used for investing activities for the year ended December 31, 2010 to the year ended December 31, 2009 was due to higher capital expenditures related to the growth of our hydraulic fracturing services. The decrease in cash used for investing activities for the year ended December 31, 2009 to the year ended December 31, 2008 was due to a reduction in the funds used for capital equipment, which was $4.3 million for the year ended December 31, 2009 compared to $21.5 million for the year ended December 31, 2008. Our overall capital expenditures plan in 2009 was decreased due to the decline in commodity prices and the resultant decline in activity levels.

Cash Flows Provided by (Used in) Financing Activities

 

Net cash provided by financing activities was $30.0 million for the six months ended June 30, 2011 as compared to net cash used in financing activities of $0.6 million for the same period in 2010. The increase was primarily due to net borrowings under our credit facility during the first half of 2011 to fund our capital spending program and the acquisition of Total. 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 and net cash provided by financing activities of $11.9 million for the year ended December 31, 2008. The increase in cash provided by financing activities for the year ended December 31, 2010 compared to the prior year 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. The sources of cash for financing activities for the year ended December 31, 2008 were $11.9 million of net borrowings under our debt facilities. Borrowings were used to fund capital expenditures and for general corporate purposes.

 

Contractual Obligations

 

The following table summarizes our contractual cash obligations as of December 31, 2010 (in thousands):

 

 

 

 

For additional discussion related to our short-term and long-term obligations, please read Note 2 to the unaudited consolidated financial statements for the six months ended June 30, 2011 included elsewhere in this prospectus.

 

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 June 30, 2011.

Description of Our Indebtedness

 

The following is a summary description of our outstanding indebtedness. This summary is not a description of all of the terms of such indebtedness and is qualified in its entirety by reference to our credit facility, which has been filed as an exhibit to the registration statement of which this prospectus forms a part.

 

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 L/C issuer, Comerica Bank, as L/C issuer and syndication agent, Wells Fargo Bank, National Association, as documentation agent, and various lenders. Our obligations under our credit facility are guaranteed by our subsidiaries C&J Spec-Rent Services, Inc. and Total (the “Subsidiaries”). 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. Currently, there are no amounts outstanding under our credit facility, leaving the entire $200.0 million available for borrowing.

 

Loans under our credit facility are denominated in U.S. dollars and will mature on April 19, 2016. Outstanding loans bear interest at either LIBOR or a base rate, at our election, plus an applicable margin which, prior to our delivery of a compliance certificate for the quarter ended June 30, 2011, was equal to 1.50% for base rate loans and 2.50% for LIBOR loans. Thereafter, the applicable base rate ranges from 1.25% to 2.00% and the applicable LIBOR rate ranges from 2.25% to 3.00% based upon our Leverage Ratio. The Leverage Ratio is the ratio of funded indebtedness to EBITDA for us and our subsidiaries on a consolidated basis. As of June 30, 2011, the weighted average interest rate under our credit facility was 2.8%.

 

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

 

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, 2010, 2009 and 2008. 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.

 

Quantitative and Qualitative Disclosures About Market Risks

 

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 interest rate fluctuations. To a lesser extent, we are also exposed to risks related to increases in the prices of fuel and raw materials consumed in performing our services. We do not engage in commodity price hedging activities.

 

Interest Rate Risk.  We are exposed to changes in interest rates as a result of our floating rate borrowings under our credit facility, which has variable interest rates. The impact of a 1% increase in interest rates on our outstanding debt as of December 31, 2010, 2009 and 2008 and June 30, 2011 would have resulted in an increase in interest expense and a corresponding decrease in net income of approximately $0.7 million, $0.7 million, $0.7 million and $0.5 million, respectively.

 

Concentration of Credit Risk.  Substantially all of our customers are engaged in the oil and gas industry. This concentration of customers may impact overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. Our top ten customers accounted for approximately 94.1% of our revenues for the six months ended June 30, 2011. Our top ten customers accounted for approximately 90.2%, 90.6% and 79.9% of our revenues for the years ended December 31, 2010, 2009 and 2008, respectively. During the six months ended June 30, 2011, sales to Anadarko Petroleum, EOG Resources, Penn Virginia and Plains Exploration represented 26.3%, 20.6%, 15.8% and 12.6%, respectively, of our total sales. In 2010, sales to EOG Resources, Penn Virginia, Anadarko Petroleum and Apache represented 32.5%, 17.9%, 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. In 2008, sales to Penn Virginia, El Paso Production Oil & Gas and EOG Resources represented 24.0%, 14.4% and 10.1%, respectively, of our total sales.

 

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, 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 in our inventory are volatile and are impacted by changes in supply and

demand, as well as market uncertainty and regional shortages. Historically, we were generally able to pass along price increases to our customers; however, we may be unable to do so in the future.

 

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 operations 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 over the estimated useful lives of the related assets, which range from three to 25 years. Depreciation is computed on a straight-line basis for financial reporting purposes. Capital leases are amortized using the straight-line method over the estimated useful lives of the assets and lease amortization is included in depreciation expense. Depreciation expense charged to operations was $4.3 million and $2.2 million for the three months ended June 30, 2011 and 2010, respectively. Depreciation expense charged to operations was $7.5 million and $4.4 million for the six months ended June 30, 2011 and 2010, respectively.

 

Goodwill, Intangible Assets and Amortization.  Goodwill and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. 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. The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. We perform impairment tests on the carrying value of goodwill for each of our reporting units at least annually. 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 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. For the six months ended June 30, 2011, there were no indicators of impairment. Significant and unanticipated changes to these assumptions could require an additional provision for impairment in a future period.

Impairment of Long-Lived Assets.  We assess the impairment of our long-lived assets 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 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. We charge fees to our customers based on the amount of chemicals and proppants used in providing these services. 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 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.

 

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 $0.7 million at June 30, 2011 and $0.5 million at December 31, 2010. Bad debt expense was $70,000 and $57,500 for the three months ended June 30, 2011 and 2010, respectively, and $137,500 and $70,000 for the six months ended June 30, 2011 and 2010, respectively.

 

Stock-Based Compensation.  We recognize compensation expense related to stock-based awards, based on the grant date estimated fair value. 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 was estimated using the Black-Scholes option-pricing model and required 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 estimate our forfeiture rate based on an analysis of our actual forfeitures and will continue to evaluate the appropriateness of the forfeiture rate based on actual forfeiture experience, analysis of employee turnover and other factors. Quarterly changes in the estimated forfeiture rate can have a significant effect on reported stock-based compensation expense, as the cumulative effect of adjusting the rate for all expense amortization is recognized in the period the forfeiture estimate is changed. If a revised forfeiture rate is higher than the previously estimated forfeiture rate, an adjustment is made that will result in a decrease to the stock-based compensation expense recognized in the consolidated financial statements. If a revised forfeiture rate is lower than the previously estimated forfeiture rate, an adjustment is made that will result in an increase to the stock-based compensation expense recognized in the consolidated financial statements.

 

We will continue to use judgment in evaluating the expected term, volatility and forfeiture rate related to our stock-based compensation on a prospective basis and will incorporate these factors into our option-pricing model.

 

Each of these inputs is subjective and generally requires significant management judgment. If, in the future, we determine that another method for calculating the fair value of our stock options is more reasonable, or if another method for calculating these input assumptions is prescribed by authoritative guidance, and, therefore, should be used to estimate expected volatility or expected term, the fair value calculated for our employee stock options could change significantly. Higher volatility and longer expected terms generally result in an increase to stock-based compensation expense determined at the date of grant.

 

Income Taxes.  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 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 Financial Accounting Standards Board Accounting Standards Codification (“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 June 30, 2011 or 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 three and six months ended June 30, 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 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 ASU No. 2010-09, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” or 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. The Company adopted ASU 2010-29 on January 1, 2011. This update had no impact on our financial position, results of operations or cash flows.

 

Overview

 

We are a rapidly growing independent provider of premium hydraulic fracturing and coiled tubing services with a focus on complex, technically demanding well completions. We provide our services in conjunction with both conventional and unconventional well completions as well as workover and stimulation operations for existing wells. We compete with a limited number of service companies for what we believe to be the most complex hydraulic fracturing projects, which are typically characterized by long lateral segments and multiple fracturing stages in high-pressure formations. We believe service providers are selected for these complex projects primarily based on technical expertise, fleet capability and experience rather than solely on price. We also provide pressure pumping services and other related well stimulation services in connection with our well completion and production enhancement operations.

 

We have historically operated in what we believe to be some of the most geologically challenging basins in South Texas, East Texas/North Louisiana and Western Oklahoma. The customers we serve are primarily large exploration and production companies with significant unconventional resource positions, including EOG Resources, EXCO Resources, Anadarko Petroleum, Plains Exploration, Penn Virginia, Petrohawk, El Paso, Apache, Cabot and Chesapeake. 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.

 

We operate five modern, 15,000 pounds per square inch, or psi, pressure rated hydraulic fracturing fleets with an aggregate 172,000 horsepower, and we currently have on order three additional hydraulic fracturing fleets, which, upon delivery, will increase our aggregate horsepower to 270,000 by the end of 2012. Our hydraulic fracturing equipment is specially designed to handle well completions with long lateral segments and multiple fracturing stages in high-pressure formations. We currently operate a fleet of 15 coiled tubing units and we have three new coiled tubing units on order, which we expect to be delivered and deployed by the end of 2011. We also have 17 double pumps and nine single pumps in our standalone pressure pumping line.

 

Our hydraulic fracturing fleets and coiled tubing units are currently deployed in the Eagle Ford Shale of South Texas, the Haynesville Shale of East Texas and North Louisiana, the Permian Basin of West Texas and New Mexico and the Granite Wash of Western Oklahoma and the Texas panhandle. Recent advances in horizontal drilling and hydraulic fracturing technologies have lowered unit recovery costs in these basins and increased the potential for long-term oil and natural gas development. Additionally, the increase in the number of drilling permits awarded in the Eagle Ford, Haynesville and Granite Wash regions, coupled with the increasing complexity and technical completion requirements for many wells in these regions, are expected to drive growth in demand for our well completion services for the foreseeable future. We have and plan to continue to focus on basins with technically demanding hydraulic fracturing requirements.

 

Industry Overview

 

The energy services industry provides hydraulic fracturing and other well stimulation services to oil and natural gas exploration companies. Fracturing involves pumping a fluid down a well casing or tubing under high pressure to cause the underground 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 keeps open the cracks (fractures) created by the fracturing process in the underground formation. Proppants generally consist of sand, resin-coated sand or ceramic particles and other engineered proprietary materials. The total size of the hydraulic fracturing market, based on revenue, was estimated to be approximately $10.8 billion in 2009 and approximately $15.7 billion in 2010 based on data from Spears & Associates.

A recent trend that has increased the demand for hydraulic fracturing services in the United States has been the development of unconventional resources, such as natural gas shales and oil shales. According to the EIA, the amount of technically recoverable natural gas found in shales is 827 trillion cubic feet, which is over 35 times the amount of total dry gas produced in the United States in 2009. According to the EIA, U.S. production of natural gas from shales is projected to increase from approximately 16% of production in 2009 to 47% in 2035. According to the EIA, oil production from shale oil is also expected to rise significantly in the next 25 years, specifically from areas such as the Eagle Ford Shale, the Bakken Shale, and other unconventional oil resources.

 

Two technologies which are critical to the recovery of natural gas and oil from unconventional resources 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. In addition, horizontal wells have become longer and more complex, resulting in an increase in the number of fracturing stages per well, higher demand for horsepower per well and per job, and an increased amount of proppant and chemicals used per well.

 

The increased level of horizontal drilling is illustrated by the growing number of horizontal rigs active in United States over the past three years. This increased activity level has largely targeted unconventional resources and shale plays. The following table highlights the increase in the horizontal rig count in the United States.

 

 

 

We believe investment in domestic unconventional resources, including shale plays, has accelerated over the past five years. In recent years, well-capitalized producers have leased large acreage positions in shale plays, including those in the Eagle Ford Shale and Haynesville Shale, using short-term leases (three years or less) which require producers to drill wells to retain the acreage. To help fund their drilling program in these areas, a number of producers have also entered into joint venture transactions with large international operators and private equity sponsors. Typically, the joint venture partner will agree to fund a significant portion of the near-term drilling capital budget in exchange for an equity interest in the joint venture. These producers and their joint venture partners have committed significant capital to the development of unconventional resources, which we believe will result in sustained drilling activity.

 

We have observed increased bidding activity in our areas of operations, a growing backlog of fracturing projects, full equipment utilization and substantial pricing power for fracturing service providers. We currently expect these factors to continue to persist and the market for fracturing services to continue to be tight.

 

Growth in horizontal drilling has also resulted in increased demand for coiled tubing services and pressure pumping services. However, we believe the increases have not been as significant as in the hydraulic fracturing business.

 

Trends Impacting Our Business

 

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 through the

application of new horizontal drilling and completion technologies, including multi-stage hydraulic fracturing. 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. We believe these investments indicate a long-term commitment to development, which should mitigate the impact of short-term changes in oil and natural gas prices on the demand for our services.

 

Increased Horizontal Drilling and Greater Service Intensity in Unconventional Basins.  As a result of the higher specification equipment and increased services associated with horizontal drilling, we view the horizontal rig count as a reliable indicator of the overall increase in the demand for our services. According to Baker Hughes Incorporated, the U.S. horizontal rig count has risen from approximately 335 at the beginning of 2007 to 1,134 as of September 9, 2011, and now represents 57.9% of the total U.S. rig count. Development of horizontal wells has evolved to feature increasingly longer laterals and more fracturing stages, which has increased the requirement for advanced hydraulic fracturing and stimulation services. 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 the number of fracturing stages completed in a year.

 

Increased Demand for Expertise to Execute Complex Completions.  We believe exploration and production companies have shown a strong preference for a customized approach to completing complex wells in unconventional basins. As the fleet specifications and capability to execute complex well completions have increased, the required attention and experience to complete the most difficult fracturing jobs has also increased. Accordingly, we believe that technical expertise, fleet capability and experience are the primary differentiating factors within the industry.

 

High Levels of Asset Utilization and Constrained Supply Growth.  Asset utilization in the hydraulic fracturing industry has meaningfully increased due to the elevated levels of horizontal drilling. 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. At the same time, manufacturers have had difficulty keeping pace with the demand for new hydraulic fracturing equipment and parts. Furthermore, the higher pressures required for more complex applications combined with higher levels of asset utilization are resulting in increased attrition of existing hydraulic fracturing equipment. We believe that these trends will continue to keep supply tight in our industry for the foreseeable future.

 

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.

 

Our Services

 

We provide hydraulic fracturing, coiled tubing, pressure pumping and other related well stimulation services to our customers under a single operating segment. We have traditionally used our coiled tubing and pressure pumping services to extend our hydraulic fracturing services into new markets.

 

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. The fracturing process consists of pumping a fluid into a cased well at sufficient

pressure to fracture the producing formation. Sand, bauxite or synthetic proppants are suspended in the fluid and are pumped into the fracture to prop the fracture open. 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 significantly among each well completion or workover depending on the number of fracturing stages requested by our customers. During the six months ended June 30, 2011, we performed individual well completions ranging from a minimum of one fracturing stage to a maximum of 24 fracturing stages, with the average well completion consisting of 11 fracturing stages.

 

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 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.

 

Pressure Pumping.  Our customers utilize our pressure pumping services primarily in connection with completing new wells and remedial and production enhancement work on existing wells. Our pressure pumping services are routinely performed in conjunction with our coiled tubing services. 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.

 

Sales and Marketing

 

Our sales and marketing activities 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. Additionally, recently we have experienced an increase in unsolicited inquiries to our corporate headquarters about our services, several of which have led to hydraulic fracturing and coiled tubing jobs.

 

Customers

 

Our customers include EOG Resources, EXCO Resources, Anadarko Petroleum, Plains Exploration, Penn Virginia, Petrohawk, El Paso, Apache, Cabot and Chesapeake. Our top ten customers accounted for approximately 90.2%, 90.6% and 79.9% of our revenues for the years ended December 31, 2010, 2009 and 2008, respectively, and 94.1% of our revenues for the six months ended June 30, 2011. In 2008, sales to Penn Virginia, El Paso and EOG Resources represented 24.0%, 14.4% and 10.1%, 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. In 2010, sales to EOG Resources, Penn Virginia, Anadarko Petroleum and Apache accounted for 32.5%,

17.9%, 16.4% and 9.7%, respectively, of our total sales. The majority of our revenues are generated from our fracturing services. We currently own five fracturing fleets. We are in the process of purchasing three additional fracturing fleets. 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.

 

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 us in the foreseeable future.

 

Competition

 

The markets in which we operate are highly competitive. To be successful, a company must provide services and products that meet the specific needs of oil and natural gas exploration and production companies and drilling services contractors at competitive prices.

 

We provide our services and products across South Texas, East Texas/North Louisiana and Western Oklahoma, and we compete against different companies in each service we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies.

 

Our major competitors for our fracturing services include Halliburton, Schlumberger, Baker Hughes, Weatherford International, RPC, Inc., Pumpco, an affiliate of Complete Production Services, and Frac Tech. Our major competitors for our coiled tubing services include Halliburton, Schlumberger, Baker Hughes and a significant number of regional businesses. 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, local leadership and shale knowledge that our personnel use to deliver quality services and products.

 

Safety

 

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. Our reputation for safety has allowed us to earn work certification from several industry leaders with what we believe to be some of the most demanding safety requirements, including ConocoPhillips, Exxon Mobil Corporation and Royal Dutch Shell.

 

Suppliers

 

We purchase the materials used in our services, such as fracturing sand, fracturing chemicals, coiled tubing and fluid supplies, from various suppliers. Please read “Certain Relationships and Related Party Transactions — Supplier Agreements” beginning on page 80 of this prospectus for additional information on our related party suppliers. Where we currently source materials from a single supplier, we believe that we will be able to make satisfactory alternative arrangements in the event of interruption of supply. However, given the limited number of suppliers of certain of our raw materials, we may not always be able to make alternative arrangements should one of our supplier’s fail to deliver or timely deliver our materials. During the year ended December 31, 2010, we

purchased 5% or more of our materials or equipment from each of Economy Polymers & Chemicals, Total, SPM and Sintex Minerals & Services, Inc. During the six months ended June 30, 2011, we purchased 5% or more of our materials and equipment from Economy Polymers & Chemicals and Total.

 

Equipment

 

We operate five modern, 15,000 psi pressure rated hydraulic fracturing fleets with an aggregate 172,000 horsepower, and we currently have on order three additional hydraulic fracturing fleets, which, upon delivery, will increase our aggregate horsepower to 270,000 by the end of 2012. Our hydraulic fracturing equipment is specially designed to handle well completions with long lateral segments and multiple fracturing stages in high-pressure formations. The number of pressure pumps and related horsepower of each hydraulic fracturing fleet is currently as follows:

 

 

 

 

Each hydraulic fracturing fleet also includes the necessary blending units, manifolds, data vans and other ancillary equipment. We have the flexibility to allocate pressure pumps and other equipment among our fleets as needed to satisfy customer demand.

 

We also operate a fleet of 15 coiled tubing units, with three new coiled tubing units on order, and have 17 double-pumps and nine single-pumps in our standalone pressure pumping line.

 

We purchase the majority of our hydraulic fracturing equipment and all of our coiled tubing and pressure pumping equipment from Total, whom we recently acquired, and Stewart & Stevenson. Please read “Prospectus Summary — Recent Developments — Acquisition of Total E&S, Inc.” beginning on page 3 of this prospectus. Although we believe that we will be able to make satisfactory alternative arrangements in the event of interruption of supply from either of these companies, we cannot be certain.

 

We believe that our equipment is rigorously maintained and suitable for our current operations. Most of our hydraulic fracturing fleets are serviced by our own mechanics who work onsite or at one of our facilities. We regularly perform preventative maintenance on our equipment in order to avoid any major equipment failures which could result in extended equipment downtime.

 

We have entered into operating leases with financial institutions covering approximately $15.0 million of equipment consisting of one blender, one chemical additions truck, four fracturing sanders, twelve trailer-mounted fracturing pumps, eight freightliners and seven tractors. The operating leases terminate on August 1, 2014 and both operating leases may be extended at our election subject to certain terms and conditions. Pursuant to the operating leases, we have the option to purchase all of the leased equipment.

Principal 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 September 14, 2011, we owned or leased the following additional principal properties:

 

 

We also own or lease several 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.

 

Risk Management and Insurance

 

Our operations 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:

 

 

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.

 

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 hydraulic fracturing 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 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 our insurance and our indemnification provisions set forth above is a summary of their material terms. Future MSAs or insurance policies may change as a result of market and other conditions.

 

Legal Proceedings

 

We are subject to various legal proceedings and claims 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 financial condition or results of operations.

 

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

 

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

 

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

 

Some of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the United States Nuclear Regulatory Commission, or 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 foreign, federal, state and local environmental, health and safety laws, rules 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, or RCRA, and comparable state statutes. The 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. 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, which we refer to herein as CERCLA or the Superfund law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and natural gas 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 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, or 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, or 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. In addition, the Oil Pollution Act of 1990 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 a 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.

 

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. 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 in our fracturing services, and we do not expect this change to have a material impact on our operations. 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. 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. 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 in the last few sessions to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Although the federal legislation did not pass, 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 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 natural gas wells in shale formations, increase our costs of compliance and adversely affect the hydraulic fracturing services that we render for our exploration and production customers. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business.

 

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

 

We maintain insurance against some risks associated with underground contamination that may occur as a result of well services activities. However, this insurance is limited to activities at the 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 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” and “Maximum Achievable Control Technology” 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 New Source Performance Standards (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 maximum achievable control technology (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 subject to these requirements, 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 an adverse effect on the demand for our products and services. Final action on the proposed rules is expected no later than February 28, 2012.

 

More stringent laws and regulations relating to climate change and GHGs 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 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 climate changes. Based on these findings, EPA has begun to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which will require that certain large stationary sources obtain permits for their emissions of GHGs, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG sources, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. 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 an adverse effect on the demand for our products and services.

 

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and more than one-third of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. 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, or 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 September 14, 2011, we had 893 employees, 191 of whom were full-time salaried personnel. Most of the remaining employees are hourly personnel. We will hire additional employees for certain 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.

 

Formation

 

We were initially formed as a partnership in 1997 pursuant to the laws of the State of Texas. In 2005, the assets of the partnership were purchased by C&J Spec-Rent Services, Inc. In 2006, we reorganized as a corporation by merging C&J Spec-Rent Services, Inc. with and into a newly-formed Texas corporation, pursuant to a merger agreement between us, C&J Merger Sub, Inc., and C&J Spec-Rent Services, Inc. Concurrent with the reorganization, we named the company C&J Energy Services, Inc. In 2010, we converted from a Texas corporation to a Delaware corporation. C&J Spec-Rent Services, Inc. is a wholly-owned subsidiary of our company and owns most of our assets. Our remaining assets are held by Total.

 

Executive Officers and Directors

 

Our board of directors is comprised of the following seven members: Joshua E. Comstock, as Chairman of the board; Randall C. McMullen; 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 “Certain Relationships and Related Party Transactions — Amended and Restated Stockholders’ Agreement” beginning on page 78 of this prospectus. Under the terms of the Amended and Restated Stockholders’ Agreement, subject to retaining certain ownership thresholds:

 

 

Set forth below are the names, ages and positions of our executive officers and directors as of September 14, 2011. 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.