S-1 1 d223899ds1.htm FORM S-1 FORM S-1
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As filed with the Securities and Exchange Commission on September 9, 2011

Registration No. 333-            

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

Frac Tech International, LLC

to be converted as described herein into a corporation named

FTS International, Inc.

(Exact name of registrant as specified in its charter)

 

 

Delaware   1389   45-1610731

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

  (I.R.S. Employer
Identification No.)

777 Main Street, Suite 3000

Fort Worth, Texas 76102

(817) 862-2000

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

 

Marcus C. Rowland

Chief Executive Officer

Frac Tech International, LLC

777 Main Street, Suite 3000

Fort Worth, Texas 76102

(817) 862-2000

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

 

Copies to:

 

Michael S. Telle

Bracewell & Giuliani LLP

711 Louisiana Street, Suite 2300

Houston, Texas 77002

(713) 221-1327

 

David J. Beveridge

Shearman & Sterling LLP

599 Lexington Avenue

New York, New York 10022

(212) 848-4000

 

Approximate date of commencement of proposed sale to the public:  As soon as practicable after the effective date of this registration statement.

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:  ¨

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

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.  ¨

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.  ¨

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):

 

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

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to Be Registered

 

Proposed Maximum
Aggregate

Offering Price(1)(2)

  Amount of
Registration Fee(3)

Common Stock, par value $0.001 per share

  $1,150,000,000   $84,318

 

 

(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.
(2) Includes approximately $150,000,000 attributable to shares of common stock that may be offered upon exercise of a 30-day option granted to the underwriters to cover over-allotments, if any.
(3) A registration fee in the amount of $49,197 was previously paid by Frac Tech Services, Inc., a wholly owned subsidiary of the registrant, in connection with the filing of a Registration Statement on Form S-1 (Registration No. 333-171162) on December 14, 2010. Pursuant to Rule 457(p) under the Securities Act, the filing fee of $49,197 previously paid by Frac Tech Services, Inc. is being used to offset the filing fee of $133,515 required for the filing of this Registration Statement.

 

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 Commission acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

Subject to Completion

Preliminary Prospectus dated September 9, 2011

PROSPECTUS

                 Shares

FTS International, Inc.

Common Stock

 

 

This is FTS International’s initial public offering. We are selling                  shares of our common stock and the selling stockholder is selling                  shares of our common stock. We will not receive any proceeds from the sale of shares to be offered by the selling stockholder.

We expect the public offering price to be between $         and $         per share. Currently, no public market exists for the shares. After pricing of the offering, we expect that the shares will trade on the New York Stock Exchange under the symbol “            .”

Investing in our common stock involves risks that are described in the “Risk Factors” section beginning on page 18 of this prospectus.

 

 

 

      

Per Share

      

Total

 

Public offering price

     $                      $                

Underwriting discount

     $                      $                

Proceeds, before expenses, to us

     $                      $                

Proceeds, before expenses, to the selling stockholder

     $                      $                

The underwriters may also exercise their option to purchase up to an additional                  shares from us, and up to an additional                  shares from the selling stockholder, at the public offering price, less the underwriting discount, for 30 days after the date of this prospectus to cover over-allotments, if any.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The shares will be ready for delivery on or about                     , 2011.

 

 

 

BofA Merrill Lynch   Goldman, Sachs & Co.

 

Citigroup   Credit Suisse

 

 

The date of this prospectus is                     , 2011.


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Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     18   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     32   

USE OF PROCEEDS

     33   

DIVIDEND POLICY

     33   

CAPITALIZATION

     34   

DILUTION

     35   

SELECTED CONSOLIDATED FINANCIAL DATA

     36   

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     38   

BUSINESS

     57   

MANAGEMENT

     81   

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     86   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     97   

HISTORY AND CONVERSION

     101   

PRINCIPAL AND SELLING STOCKHOLDERS

     102   

DESCRIPTION OF CAPITAL STOCK

     104   

SHARES  ELIGIBLE FOR FUTURE SALE

     108   

DESCRIPTION OF CERTAIN INDEBTEDNESS

     110   

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS TO NON-U.S. HOLDERS

     113   

UNDERWRITING

     117   

LEGAL MATTERS

     124   

EXPERTS

     124   

WHERE YOU CAN FIND MORE INFORMATION

     125   

INDEX TO FINANCIAL STATEMENTS

     F-1   

 

 

We are responsible for the information contained in this prospectus and in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. We and the underwriters are offering to sell, and seeking offers to buy, these securities 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 these securities.

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. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.

 

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PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. This summary does not contain all the information that you should consider before investing in our common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and related notes thereto included elsewhere in this prospectus.

The historical financial information presented in this prospectus for periods and as of dates prior to May 6, 2011 is the historical consolidated financial information of Frac Tech Holdings, LLC, which we refer to as our “predecessor.” The historical financial information presented in this prospectus for periods and as of dates on or after May 6, 2011 is the historical consolidated financial information of Frac Tech International, LLC, which we will convert into a Delaware corporation named FTS International, Inc. prior to the consummation of this offering. In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” refer to Frac Tech Holdings, LLC and its subsidiaries and predecessor entities before May 6, 2011, to Frac Tech International, LLC and its subsidiaries on or after May 6, 2011 until the time of its conversion into a Delaware corporation and to FTS International, Inc. and its subsidiaries from and after such conversion. See “History and Conversion.”

Our Company

We are a leading independent provider of oil and natural gas well stimulation services with expertise in high-pressure hydraulic fracturing. We currently operate 33 hydraulic fracturing fleets with 1,393,500 horsepower in the aggregate. We have leading positions in the primary U.S. shale plays and are actively exploring international expansion into areas where the geology is similar to the U.S. unconventional basins in which we currently operate. We are vertically integrated unlike the majority of our competitors. We manufacture many of the components of our hydraulic fracturing units, mine, process and transport a majority of our proppant requirements and formulate and blend a portion of the chemicals we use in our operations.

We believe the vertical integration of our operations reduces our operating costs, increases our asset utilization, improves our supply chain flexibility and responsiveness and ultimately enhances our financial performance and ability to provide high-quality customer service. We manufacture durable equipment based on proprietary designs that we believe provides superior performance in the most demanding applications while extending the useful life of our equipment. Unlike manufacturers without service operations, we are able to incorporate the knowledge acquired in our hydraulic fracturing operations to improve our equipment designs. We also have significant maintenance and repair capabilities, and we manufacture replacement parts to support our operations and enhance our asset utilization. Our raw sand reserves and processing operations provide us with ready access to the two principal proppants we use in our operations, raw sand and resin-coated sand, which can often be in short supply in the required specifications. Additionally, we formulate and blend a portion of the chemical compounds we use in our operations, which allows us to provide tailored solutions to our customers. Our chemical offerings include some of the most environmentally friendly products in the industry, most of which produce no harmful by-products and require no auxiliary chemicals. Our technical staff of engineers, chemists, technicians and a geologist support our operations by optimizing the design and delivery of our equipment, products and services and by continually seeking to improve the quality, durability and effectiveness of the solutions we provide to our customers.

Our revenues have grown from $214.4 million in 2006 to $1,286.6 million in 2010, a compound annual growth rate of 56.5%. For the six months ended June 30, 2011 our revenues were $1,096.4 million and our Adjusted EBITDA was $453.5 million, representing increases of 143% and 178%, respectively, compared to the

 

 

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six months ended June 30, 2010. We are benefitting from a number of positive industry developments, including a dramatic increase in the amount and efficiency of horizontal drilling activity, an increase in the number of hydraulic fracturing stages per well and an increase in drilling activity in oil- and liquids-rich shale formations. These trends have led to increased asset utilization in our industry and a tight supply of fracturing fleets, proppants and other fracturing-related services and products. We also believe there is growing international interest in horizontal drilling and fracturing methods.

Our fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of a high-pressure hydraulic pump, a diesel engine, a transmission and various hoses, valves, tanks and other supporting equipment that are typically mounted on a flat-bed trailer. The group of hydraulic fracturing units, other equipment and vehicles necessary to perform a typical fracturing job is referred to as a “fleet” and the personnel assigned to each fleet are commonly referred to as a “crew.” In areas where we operate on a 24-hour-per-day basis, we typically staff two crews per fleet. The following table summarizes the amount of horsepower and the number of hydraulic fracturing fleets that we operate as of August 31, 2011:

 

Formation

 

Location

  Total
Horsepower
    Fleets  

Haynesville Shale

  Louisiana, East Texas     396,750        7   

Eagle Ford Shale

  South Texas     281,000        6   

Marcellus Shale

  Pennsylvania, West Virginia     242,750        6   

Permian Basin

  West Texas, New Mexico     201,550        7   

Bakken Shale

  North Dakota, Montana     106,750        3   

Granite Wash

  Oklahoma, North Texas     97,500        2   

Barnett Shale

  North Texas     45,000        1   

Rockies

  Utah     22,200        1   
   

 

 

   

 

 

 

Total

      1,393,500        33   

Exploration and production (“E&P”) companies operating in the United States use our services primarily to enhance their recovery rates from wells drilled in shale and other unconventional reservoirs. Our operations are focused primarily in unconventional oil and natural gas formations in the Haynesville Shale, the Eagle Ford Shale, the Marcellus Shale, the Permian Basin and the Bakken Shale. We believe we have one of the largest market shares of any hydraulic fracturing service provider in the Haynesville Shale, the Eagle Ford Shale and the Marcellus Shale, based on number of fleets. In recent months, we have obtained an increasing number of engagements in connection with oil-directed drilling, particularly in the Eagle Ford Shale and the Permian Basin. In 2011, we began serving customers in the Bakken Shale and the Granite Wash formation. Our engagements in these areas primarily relate to horizontal drilling for oil and other hydrocarbon liquids. We expect to continue to deploy new fleets in additional regions with significant oil- and liquids-directed drilling activity through the end of 2011. The customers we currently serve are primarily large E&P companies such as Chesapeake Energy Corporation (“Chesapeake”), Anadarko Petroleum Corporation, El Paso Corporation, Marathon Oil Corporation, Petrohawk Energy (owned by BHP Billiton Ltd.), Range Resources Corporation and XTO Energy (owned by Exxon Mobil Corporation).

We currently manufacture many of the components of our hydraulic fracturing units, including all of the hydraulic pumps, and we assemble all of the hydraulic fracturing units in our fleets. At full capacity, we are capable of producing up to 30 hydraulic fracturing units, with an aggregate of approximately 75,000 horsepower, per month. To increase the durability, reliability and utilization of our hydraulic fracturing units, we manufacture a proprietary hydraulic pump consisting of two key assemblies, a power end and a fluid end. Although the power end of our pumps generally lasts several years, the fluid end, which is the part of the pump through which the fracturing fluid is expelled under high pressure, is a shorter-lasting consumable, often lasting less than one year. We currently have the capacity to manufacture up to 30 power ends and 150 fluid ends per month to equip new

 

 

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hydraulic fracturing units and to replace the fluid ends on our existing units. Because we build and service our own fluid ends, they are designed to provide high performance at low cost and to have greater longevity than those manufactured by third parties.

We own and operate sand mines, related processing facilities, resin-coating facilities and a distribution network that provide us with a reliable and low cost supply of raw and resin-coated sand. Our raw sand operations supplied approximately 65.1% and 76.5% of the raw sand we used as proppants in our hydraulic fracturing operations during 2010 and the six months ended June 30, 2011, respectively. Our resin-coating operations supplied approximately 49.3% and 57.6% of the resin-coated sand we used as proppants during 2010 and the six months ended June 30, 2011, respectively. We have processing plants at our two sand mines in Texas and Missouri and also obtain and process sand from agricultural sources in Wisconsin. We are currently capable of processing approximately 1.9 million tons per year of raw sand, which is the most common type of proppant we use in our hydraulic fracturing operations. As of June 30, 2011, we had an estimated 313 million tons of probable sand reserves. See “Business—Sand Production and Distribution—Sand Reserves.” Our resin-coating facilities currently have the capacity to produce approximately 650,000 tons of resin-coated sand annually. Resin-coated sand is raw sand that has been processed and coated with resin and has a greater resistance to crushing forces compared to raw sand. We use resin-coated sand as a proppant in the more geologically challenging formations that require fracturing at higher pressures. We intend to expand our raw sand and resin-coated sand production capacity over the next 12 months. See “Business—Sand Production and Distribution—Sand Production.” In addition to our mines and processing plants, we have eight operating sand distribution facilities in Texas, Louisiana and Pennsylvania, 218 bulk hauling trailers for highway transportation and approximately 2,050 rail cars, which enable us to deliver proppants to our fracturing jobs quickly and on short notice.

In addition, we formulate and blend a portion of the chemical compounds that we use in fracturing fluids at our chemical manufacturing facility and research and development laboratories.

Industry Overview

The pressure pumping industry provides hydraulic fracturing and other well stimulation services to E&P companies. Hydraulic 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 props open the cracks created by the hydraulic fracturing process in the underground formation. Proppants generally consist of sand, resin-coated sand or ceramic particles. The total size of the hydraulic fracturing market, based on revenue, was estimated to be approximately $10.5 billion in 2009, $18.0 billion in 2010 and is estimated to be $22.5 billion in 2011 based on data from a 2011 report by Spears & Associates.

When drilling a horizontal well, the E&P company directs drillers to drill vertically into the formation, and steer the drill string to create a horizontal section of the wellbore inside the target formation, which is referred to as a “lateral.” This lateral is divided into “stages” which are isolated zones that focus the high-pressure fluid and proppant from the hydraulic fracturing fleet into distinct portions of the wellbore and surrounding formation. Customers typically compensate hydraulic fracturing service providers based on the number of stages fractured.

The main factors influencing demand for hydraulic fracturing services in North America are the level of horizontal drilling activity by E&P companies and the fracturing requirements, including the number of fracturing stages and the volume of fluids, chemicals and proppant pumped per stage, in the respective resource plays. The hydraulic fracturing market is cyclical and is largely influenced by drilling and completion expenditures by our customers. Since late 2009, there has been a significant increase in both horizontal drilling activity and related hydraulic fracturing requirements, which has increased the demand for our services.

 

 

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Industry Trends Impacting Our Business

Industry revenues are generally impacted by the following trends and have recently been growing significantly in excess of rig count.

Increase in Fracturing Stages Resulting from Horizontal Drilling Activity

Advances in drilling and completion technologies including horizontal drilling and hydraulic fracturing have made the development of many unconventional resources, such as oil and natural gas shale formations, economically attractive. This has led to a dramatic increase in the development of oil- and natural gas-producing shale formations, or “plays,” in the United States. According to Baker Hughes, the U.S. horizontal rig count has risen from 337 at the beginning of 2007 to 1,136 at September 2, 2011, increasing from 20% to 58% of total rig count. As E&P companies have become more experienced at developing shale plays, the time required to drill wells has decreased, thus increasing the number of wells drilled per year and hence the number of fracturing stages demanded for a given rig count. At the same time, the length of well laterals is increasing, and fracturing stages are being performed at closer intervals. As a result, the number of fracturing stages is growing at a faster rate than the horizontal rig count, leading to a significant increase in the demand for hydraulic fracturing services.

Increased Service Intensity and Activity in More Demanding Shale Reservoirs

Many of the new shales that have been discovered, such as the Haynesville and Eagle Ford Shales, are high-pressure reservoirs that require more durable equipment, a greater amount of horsepower and more technically sophisticated forms of proppant, such as resin-coated sand and ceramic proppants. The additional horizontal drilling activity, coupled with the demanding characteristics of unconventional reservoirs, has put increasing demands on hydraulic fracturing equipment. We focus on the most demanding reservoirs where per stage revenues are higher and where we believe we have a competitive advantage due to the high performance and durability of our equipment.

Increased Drilling in Oil- and Liquids-Rich Formations

There is increasing drilling activity in oil- and liquids-rich formations in the United States, such as the Eagle Ford, Bakken, Niobrara and Utica Shales and various plays in Oklahoma, including the Granite Wash formation. Additionally, hydraulic fracturing services are increasingly being deployed in traditionally oil-focused basins like the Permian Basin. Although the E&P industry is cyclical and oil prices have historically been volatile, we believe that many of the oil- and liquids-rich plays are economically attractive at oil prices substantially below the current prevailing oil price. We believe this should provide continued and growing opportunities for our services in the near term.

Tight Supply of Hydraulic Fracturing Fleets, Proppants and Other Products

Due to increased drilling in unconventional formations, hydraulic fracturing fleets, proppants, replacement and repair parts and other products became increasingly scarce since 2010, as demand increased for hydraulic fracturing services. Moreover, individual fracturing stages have become more intensive, requiring more fluids, chemicals and proppant per stage. Based on current market conditions, we expect this trend to continue throughout 2011 and into 2012. We are well positioned to take advantage of the market scarcity due to our vertical integration strategy because we supply our own hydraulic pumps and the majority of our proppant requirements, and we manufacture many of the components of and repair our hydraulic fracturing units in-house.

 

 

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Growing International Interest in Hydraulic Fracturing

There is growing international interest in the development of unconventional resources such as oil and natural gas shales. This interest has resulted in a number of recently completed joint ventures between major U.S. and international E&P companies related to shale plays in the United States. We believe that these joint ventures, which generally require the international partner to commit to significant future capital expenditures, will provide additional demand for hydraulic fracturing services in the coming years. Additionally, we believe such joint ventures will continue to stimulate the development of other oil and natural gas shales outside the United States. The technological advances seen in the United States over the last five years can be applied to unconventional basins internationally, allowing foreign countries to reach the level of drilling and fracturing efficiency currently being achieved in the United States. We believe rapid development of cost-effective oil and natural gas reserves has the potential to provide an attractive source of energy for rapidly developing emerging economies.

Competitive Strengths

We believe that we have the following competitive strengths:

Vertically Integrated Business

Our vertical integration provides us with a number of competitive advantages. For example, the amount of time required to fabricate and assemble a hydraulic fracturing unit is significantly reduced as a result of our in-house capabilities. Moreover, once our units are deployed, they are able to continue to operate with minimal delays for our customers, because our ability to quickly provide replacement fluid ends and other consumables reduces our maintenance turnaround time. Similarly, our raw sand and resin-coating operations provide a reliable source of proppant for our operations. Our sand distribution centers and our transportation infrastructure reduce the logistical challenges inherent in our business by allowing us to transport and deliver proppant and equipment quickly to our fracturing jobs on short notice.

Because we produce most of the key equipment and products necessary for our operations, we are able to provide prompt service while controlling costs. We estimate that our manufacturing costs per fracturing unit are approximately 30% less than we would pay to purchase a similar fracturing unit from outside suppliers and that our manufacturing cost per fluid end is approximately 50% less than we would pay to purchase a similar fluid end from outside suppliers. Similarly, we are able to produce proppants such as raw sand and resin-coated sand and to blend chemicals at lower cost than we would typically pay for such products from outside suppliers. As a result, our vertically integrated business improves our margins, reduces our maintenance capital expenditures and improves our equipment utilization. These factors enable us to provide superior service at competitive prices, thereby increasing customer satisfaction, strengthening our existing customer relationships and helping us to expand our customer base.

High-Quality Fleet

We maintain high-quality fleets of hydraulic fracturing units and related equipment. Our 33 fleets have 1,393,500 horsepower in the aggregate, are strategically located throughout our principal markets and have an average age of less than four years. We believe our fleets are among the most reliable and highest performing in the industry with the capability of meeting the most demanding pressure and flow rate requirements in the field. Our equipment’s durability minimizes delays and reduces maintenance costs. Moreover, we maintain our high-quality fleets through our manufacturing and repair facilities and our maintenance and repair personnel who work out of our district offices, which allow us to service, repair and rebuild our equipment quickly and efficiently without incurring excessive costs. These factors increase utilization of our fleets and enhance customer satisfaction because of reduced down time and delays.

 

 

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Advanced Equipment and Products

Our engineering team has enabled us to create what we believe to be one of the most technologically advanced and durable fleets of hydraulic pumps in the industry. We believe that, within the industry, we manufacture and deploy one of the most durable fluid ends, which is the part of the high-pressure pump that requires replacement most frequently. We also have chemical blending and research and development facilities where our technical staff designs and improves upon the composition of the chemicals we add to hydraulic fracturing fluids based on specific customer needs and geological factors. For example, we have filed a U.S. patent application for a new additive that uses nano particles to enhance the recovery of hydrocarbons from significantly depleted hydrocarbon formations. In addition, our technical staff has developed innovative techniques for completing and stimulating wells in unconventional formations that have helped establish us as a market leader in our industry.

Highly Active, High-Quality Customer Base

We have long-standing relationships with many of the leading oil and natural gas producers operating in the United States. Our largest customers include Chesapeake, El Paso Corporation, Petrohawk Energy (owned by BHP Billiton Ltd.), Range Resources Corporation and XTO Energy (owned by Exxon Mobil Corporation). Since 2002, we have broadened our customer base as a result of our technical expertise, high-quality hydraulic fracturing fleets and reputation for quality and customer service. We currently have more than 170 customers. Our strong customer relationships provide us with significant revenue visibility in the near to intermediate term and facilitate our ability to opportunistically expand our business to provide services to our customers in multiple areas in which they have operations. In addition, we have dedicated a larger portion of our fleets to some of our largest customers.

Leading Market Share in Key Unconventional Resource Plays

As a result of our focus on superior service and strong customer relationships, we believe we have one of the largest market shares of any hydraulic fracturing company in the Haynesville Shale, the Eagle Ford Shale and the Marcellus Shale, based on number of fleets. In addition to our current leading positions, we have recently begun serving customers in the Bakken Shale and the Granite Wash formation, and we have plans to expand into other prolific unconventional resource plays where significant demand exists for high-quality hydraulic fracturing services. Our leading market positions in the most demanding shale plays create economies of scale that allow us to more efficiently deploy our crews and to increase our productivity, efficiency and performance.

Incentivized Work Force

The managers of our hydraulic fracturing crews are eligible to receive incentive pay per fracturing stage based on customer and senior management satisfaction and subject to satisfying quality and safety standards. In addition, all of our field employees are eligible for incentive pay based on customer and management satisfaction and satisfying safety standards. We believe these incentive programs enable us to achieve higher utilization, attract the most competent work force and motivate our employees to continually maintain quality and safety. The discretionary incentive pay available under these programs has the potential to significantly supplement the earnings of our fleet managers and field employees.

Experienced Management Team

We have an experienced management team that includes Marcus C. Rowland, our chief executive officer, James Coy Randle, Jr., our president and chief operating officer, Charles Veazey, our senior vice president of operations, Robert Pike, our senior vice president of sales, Chris Cummins, our senior vice president

 

 

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of proppants, and Brad Holms, our senior vice president—global business development and technology, who collectively have over 190 years of oilfield business experience. The remainder of our management team is comprised of seasoned operating, marketing, financial and administrative executives, many of whom have prior experience at prominent oilfield service companies such as BJ Services Company, Halliburton Corporation and Schlumberger Limited. Our management team’s extensive experience in, and knowledge of, the oilfield services industry strengthens our ability to compete and manage our business through industry cycles.

Strategy

We intend to build upon our competitive strengths to grow our business and increase our revenues and operating income. Our strategy to achieve these goals consists of (1) expanding our geographic footprint in the United States and internationally, (2) increasing our proppant production and distribution and our equipment manufacturing capabilities, (3) continuing to enhance our contract terms, (4) further increasing asset utilization and (5) evaluating opportunities for complementary services.

Expand Geographic Footprint in the United States and Internationally

We will continue to expand our operations to regions containing unconventional formations that are likely to require multi-stage high-pressure hydraulic fracturing efforts. For example, we deployed six fleets with approximately 281,000 aggregate horsepower to serve customers in the Eagle Ford Shale since June 30, 2010. In the first half of 2011, we deployed five new fleets with approximately 177,500 aggregate horsepower to serve customers in the Granite Wash formation and the Bakken Shale.

We are exploring international expansion into areas where the geology is similar to the U.S. unconventional basins in which we currently operate. By applying our technologies to these new areas we believe we can help producers achieve levels of drilling and completion efficiencies comparable to those in the United States in less time than it took in the U.S. market. Based on a report from the U.S. Department of Energy, international shale gas recoverable reserves are 6.7 times those in the United States. We are actively working to establish relationships with local reserve holders and to provide them stimulation services at the appropriate time in their development plans. We currently believe the most attractive international markets for our services are China, the Middle East and South America.

Increase Proppant Production and Distribution and Equipment Manufacturing Capabilities

We intend to increase our raw sand production capacity by expanding our existing processing plants in Texas and opening an additional sand processing plant in Texas. In addition, we plan to continue to increase our resin-coated sand production capacity over the next few years, and are constructing a new resin-coating plant in Texas that we expect to complete later in 2011. We are enlarging our distribution network to support the expansion of our sand operations. We also intend to increase our hydraulic pump manufacturing capacity and enhance our manufacturing capabilities by expanding our existing plants and adding new plants.

Continue to Enhance Contract Terms

We intend to continue to enhance our contract terms with our customers to increase the predictability of our future revenues, improve our ability to deploy fleets efficiently and enhance our customer relationships. In response to increased demand and tight supply of fracturing fleets in some of our key markets, we have agreed with some of our customers to dedicate one or more of our fleets to their operations at agreed prices. These arrangements typically have 12- to 24-month terms and require customers to pay us an established rate per fracturing stage or a minimum amount per quarter. We have entered into such arrangements with 12 of our

 

 

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largest customers operating in the Haynesville, Eagle Ford, Marcellus and Bakken Shales and the Permian Basin. Currently, about one-third of our fleets are dedicated to customers under these types of arrangements.

Further Increase Asset Utilization

We will continue to focus on increasing asset utilization, particularly in the most demanding reservoirs. We are generally compensated based on the number of fracturing stages we complete. Each of our fleets historically completed one fracturing stage per day, but our fleets now typically complete multiple stages per day, usually on the same well. We have the ability to operate our fleets on a 24-hour-per-day, seven-day-per-week basis with two crews rotating to increase asset efficiency. Increases in the number of stages per well allow us to increase revenues for a given crew by reducing travel and mobilization time between jobs. In addition, we seek to increase asset utilization by scheduling fracturing jobs that are geographically close to one another.

Evaluate Opportunities for Complementary Services

We will continue to seek opportunities to further grow our business by adding complementary service offerings. We expect that any new services that we may add will be focused primarily on improving the quality, reliability and deliverability of our existing service offerings.

History and Conversion

We were originally formed as a Texas limited partnership in August 2000 and began providing hydraulic fracturing services to E&P companies in 2002.

On May 6, 2011, our prior majority owners sold their 74.2% interest in Frac Tech Holdings, LLC to Frac Tech International, LLC, a newly-formed Delaware limited liability company controlled by an investor group comprised of Maju Investments (Mauritius) Pte Ltd, an indirect wholly owned investment holding company of Temasek Holdings (Private) Limited (“Temasek”), Senja Capital Ltd (“Senja”) and other investors. In connection with the transaction, which we refer to as the “Acquisition Transaction,” Chesapeake contributed its 25.8% interest in Frac Tech Holdings, LLC to Frac Tech International, LLC in exchange for cash and limited liability company units representing 30% of Frac Tech International, LLC’s outstanding limited liability company units.

 

 

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Table of Contents

The chart below depicts our organizational structure after giving effect to our conversion into a Delaware corporation named FTS International, Inc., which we refer to as our “Conversion,” and our initial public offering. For more information, see “Principal and Selling Stockholders.”

LOGO

Company Information

Our principal executive offices are located at 777 Main Street, Suite 3000, Fort Worth, Texas 76102, and our telephone number at that address is (817) 862-2000. Our website address is http://www.fractech.net. However, information contained on our website is not incorporated by reference into this prospectus, and you should not consider the information contained on our website to be part of this prospectus.

 

 

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Table of Contents

The Offering

 

Common stock offered by us

                 shares

 

Common stock offered by selling stockholder

                 shares

 

Common stock outstanding after the offering

                 shares

 

Over-allotment option

We and the selling stockholder have granted the underwriters an option, exercisable for 30 days, to purchase up to an aggregate of                      additional shares of our common stock to cover over-allotments, if any.

 

Use of proceeds

We expect to receive approximately $         million of net proceeds from the sale of the common stock offered by us, based upon the assumed initial public offering price of $         per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $         million.

 

  We intend to use all of the net proceeds we receive from this offering to repay outstanding borrowings under our senior secured term loan. See “Use of Proceeds.”

 

  We will not receive any of the net proceeds from the sale of the common stock offered by the selling stockholder.

 

Dividend policy

After this offering, we do not anticipate paying cash dividends on our common stock in the foreseeable future. See “Dividend Policy.”

 

Proposed NYSE symbol

“                    ”

Unless otherwise indicated, all share information contained in this prospectus:

 

   

assumes the consummation of our Conversion, as described under “History and Conversion;”

 

   

assumes that the underwriters’ over-allotment option granted by us and the selling stockholder will not be exercised; and

 

   

does not include                  shares of common stock reserved for issuance under our 2011 Long-Term Incentive Plan to be approved by our board of directors and stockholders immediately prior to the completion of this offering.

 

 

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Risk Factors

An investment in our common stock involves significant risks. Before investing in our common stock, you should carefully consider all the information contained in this prospectus, including the information under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” Our business, financial condition and results of operations could be materially and adversely affected by many factors, including the following factors and the factors discussed in “Risk Factors” and elsewhere in this prospectus:

 

   

the cyclical nature of demand for hydraulic fracturing and other stimulation services;

 

   

volatility in market prices for oil and natural gas and in the level of E&P activity in the United States, and the effect of this volatility on the demand for oilfield services generally;

 

   

changes in legislation and the regulatory environment;

 

   

liabilities and risks, including environmental liabilities and risks, inherent in oil and natural gas operations;

 

   

the loss of any of our key executives;

 

   

continuing or increased competition;

 

   

our inability to fully protect our intellectual property rights;

 

   

delays by our customers or by us in obtaining permits necessary for the conduct of our operations; and

 

   

dependence on a limited number of major customers.

 

 

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Summary Consolidated Financial Information

The following summary consolidated financial information for each of the years in the three-year period ended December 31, 2010 is based on the audited consolidated financial statements of our predecessor included elsewhere in this prospectus. The summary consolidated financial information for the six months ended June 30, 2010 and the partial periods from January 1, 2011 through May 5, 2011 and May 6, 2011 through June 30, 2011 is based on our unaudited consolidated financial statements included elsewhere in this prospectus. The summary consolidated financial information for the year ended December 31, 2007 is based on the audited consolidated financial statements of our predecessor not included in this prospectus. The summary consolidated financial information for the year ended December 31, 2006 is based on the unaudited consolidated financial statements of our predecessor not included in this prospectus. In the opinion of our management, the interim financial information includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of our financial condition, results of operations and cash flows. The results for interim periods set forth below are not necessarily indicative of the results to be expected for the full year.

We recorded the Acquisition Transaction using the acquisition accounting method, under which the assets acquired and liabilities assumed were recorded at their estimated fair values as of May 6, 2011. The selected financial data below is presented on a “predecessor” basis for periods prior to May 6, 2011 and “successor” basis for periods beginning on or after May 6, 2011 to indicate the application of two bases of accounting and on a combined basis for the six month period ended June 30, 2011. Even though our operations did not change significantly due to the Acquisition Transaction, the expenses related to these changes in our basis of accounting affect certain expenses recognized in the successor period, thereby impacting the comparability of successor period and predecessor period financial information.

The information set forth below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and related notes thereto included elsewhere in this prospectus.

 

    Predecessor          Successor     Combined  
    Year Ended December 31,     Six Months
Ended
June  30,
2010
    January  1
through
May 5,
2011
         May  6
through

June 30,
2011
    Six Months
Ended
June  30,
2011
 
    2006     2007     2008     2009     2010               
    (Unaudited)                             (Unaudited)     (Unaudited)          (Unaudited)     (Unaudited)  
                            (In thousands)                             

Income Statement Information:

                     

Revenues

  $ 214,426      $ 362,462      $ 573,543      $ 389,230      $ 1,286,599      $ 451,874      $ 729,365          $ 366,997      $ 1,096,362   

Costs of revenues, excluding depreciation, depletion and amortization

    88,246        202,620        343,301        255,977        641,783        245,482        365,480            245,763        611,243   

Selling and administrative costs

    20,731        35,006        81,940        68,386        136,299        49,091        88,695            30,001        118,696   

Depreciation, depletion and amortization

    15,646        38,938        69,200        91,149        117,976        52,959        52,553            49,134        101,687   

Goodwill impairment

    —          —          5,971        —          —          —          —              —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Income (loss) from operations

    89,803        85,898        73,131        (26,282     390,541        104,342        222,637            42,099        264,736   

Interest expense, net

    (4,963     (13,467     (29,040     (15,945     (19,476     (11,529     (13,935         (22,829     (36,764

Other income (expense), excluding interest

    53        568        1,262        2,335        865        (66     (1,347         296        (1,051
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Income (loss) before income taxes

    84,893        72,999        45,353        (39,892     371,930        92,747        207,355            19,566        226,921   

Income taxes(1)

    2,421        1,248        1,994        347        3,254        1,685        2,051            730        2,781   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Net income (loss)

  $ 82,472      $ 71,751      $ 43,359      $ (40,239   $ 368,676      $ 91,062      $ 205,304          $ 18,836      $ 224,140   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Other Financial Information:

                     

Adjusted EBITDA(2) (unaudited)

  $ 105,449      $ 124,836      $ 148,302      $ 64,868      $ 518,844      $ 162,952      $ 309,556          $ 143,956      $ 453,512   

Capital expenditures

  $ 195,727      $ 292,469      $ 163,040      $ 61,777      $ 266,050      $ 47,689      $ 188,880          $ 90,236      $ 279,116   

 

 

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Table of Contents
    Predecessor          Successor     Combined  
    Year Ended December 31,     Six
Months
Ended

June 30,
2010
    January  1
through

May 5,
2011
         May  6
through

June 30,
2011
    Six
Months
Ended

June 30,
2011
 
    2006     2007     2008     2009     2010               
Operating Data—Unaudited:                                                           

Number of wells fractured

    398        750        839        675        1,374        665        583            278        861   

Total fracturing stages

    *        *        *        4,786        9,916        4,253        5,086            2,506        7,592   

Average revenue per stage

    *        *        *      $ 81,327      $ 129,750      $ 105,155      $ 142,951          $ 140,754      $ 142,226   

Horsepower (end of period)

    213,750        678,250        779,500        802,000        996,250        802,000        1,194,000            1,312,750        1,312,750   

Number of fleets deployed (end of period)

    11        16        19        20        23        20        27            31        31   

 

* Unavailable

 

     June 30, 2011  
     Actual      As Adjusted(3)  
     (Unaudited)  
     (In thousands)  

Balance Sheet Information:

     

Cash and cash equivalents

   $ 216,979       $                

Fixed assets, net

   $ 1,378,227       $                

Total assets

   $ 5,869,648       $                

Long-term debt (including current portion)

   $ 2,063,106       $                

Owners’ equity

   $ 3,573,837       $                

 

(1) Consists primarily of State of Texas margin tax treated as income taxes for accounting purposes. Prior to our Conversion, we have been treated as a partnership for federal income tax purposes and therefore have not directly paid federal or state income taxes on our income.
(2) “Adjusted EBITDA” is a non-GAAP financial measure that we define as net income before interest, taxes, depreciation, depletion, amortization, gain or loss on sale of assets, ownership-based compensation and Acquisition Transaction costs, as further adjusted to add back amounts charged to income for goodwill impairment related to the discontinuance of the operations of a subsidiary in fiscal year 2008 and impairment of service equipment in fiscal year 2010. “Adjusted EBITDA,” as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. However, our management believes Adjusted EBITDA may be useful to an investor in evaluating our operating performance because this measure:

 

   

is widely used by investors in the oilfield services industry to measure a company’s operating performance without regard to items excluded from the calculation of such measure, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors;

 

   

helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from our operating structure; and

 

   

is used by our management for various purposes, including as a measure of performance of our operating entities, in presentations to our board of directors and as a basis for strategic planning and forecasting.

There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, and the lack of comparability of results of operations of different companies.

 

 

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Table of Contents

The following table reconciles our net income, the most directly comparable GAAP financial measure, to Adjusted EBITDA:

 

    Predecessor          Successor     Combined  
    Year Ended December 31,     Six
Months
Ended

June 30,
2010
    January  1
through

May 5,
2011
         May  6
through

June 30,
2011
    Six
Months
Ended

June 30,
2011
 
    2006     2007     2008     2009     2010               
                     

      (In thousands)

                        

Net income (loss)

  $ 82,472      $ 71,751      $ 43,359      $ (40,239   $ 368,676      $ 91,062      $ 205,304          $ 18,836      $ 224,140   

Interest expense, net

    4,963        13,467        29,040        15,945        19,476        11,529        13,935            22,829        36,764   

Income taxes

    2,421        1,248        1,994        347        3,254        1,685        2,051            730        2,781   

Depreciation, depletion and amortization

    15,646        38,938        69,200        91,149        117,976        52,959        52,553            49,134        101,687   

Goodwill impairment

    —          —          5,971        —          —          —          —              —          —     

Impairment of service equipment(a)

    —          —          —          —          9,352        5,651        —              —          —     

Loss (gain) on sale of assets

    (47     (73     (442     (50     390        338        2,244            (541     1,703   

Ownership-based compensation

    —          —          —          —          975        —          18,165            —          18,165   

Acquisition Transaction costs

    —          —          —          —          —          —          16,201            52,723        68,924   

Miscellaneous revenue(b)

    (6     (495     (820     (2,284     (1,255     (272     (897         245        (652
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Adjusted EBITDA

  $ 105,449      $ 124,836      $ 148,302      $ 64,868      $ 518,844      $ 162,952      $ 309,556          $ 143,956      $ 453,512   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

 

  (a) The amount shown in the table above for impairment of service equipment relates to a charge taken during fiscal year 2010 resulting from increased use of our equipment in demanding shale reservoirs, which required us to replace the equipment earlier than its originally estimated useful life.
  (b) Miscellaneous revenue consisted principally of the following: rebates and commissions, for fiscal years 2006 and 2007; settlement of discounts and warranty claims, for fiscal year 2008; amortization of deferred gain, for fiscal year 2009; and rental income and amortization of deferred gain, for fiscal year 2010.

 

(3) As adjusted to give effect to the closing of this offering and application of the estimated net proceeds of this offering to repay borrowings under our senior secured term loan as described in “Use of Proceeds.”

 

 

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Summary Unaudited Pro Forma Financial Information

The following tables present our unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2010 and for the six months ended June 30, 2011, and our unaudited pro forma condensed consolidated balance sheet as of June 30, 2011.

Our unaudited pro forma condensed consolidated financial statements have been developed by applying pro forma adjustments to our historical consolidated financial statements appearing elsewhere in this prospectus. The unaudited pro forma condensed consolidated statements of operations data for the periods presented give effect to our Conversion from a limited liability company to a corporation and the Acquisition Transaction as if they had been completed on January 1, 2010. The unaudited pro forma condensed consolidated balance sheet data gives effect to the Conversion as if it had occurred on June 30, 2011. The Acquisition Transaction occurred on May 6, 2011 and is reflected in our historical consolidated balance sheet as of June 30, 2011 included elsewhere in this prospectus. As a result, no pro forma adjustments to the June 30, 2011 balance sheet were necessary to reflect the Acquisition Transaction. We describe the assumptions underlying the pro forma adjustments in the accompanying notes and the notes to the unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus, which should be read in conjunction with this summary pro forma condensed consolidated financial information.

The pro forma adjustments related to the purchase price allocation of the Acquisition Transaction are preliminary and are subject to revision as additional information becomes available. Revisions to the preliminary purchase price allocation may have a significant impact on the pro forma amounts of total assets, total liabilities and owners’ equity and on depreciation, depletion and amortization expense. The pro forma adjustments related to the Acquisition Transaction reflect the fair values allocated to our assets as of May 6, 2011 and do not necessarily reflect the fair values that would have been recorded if the Acquisition Transaction had occurred on January 1, 2010.

The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the information contained in “Selected Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes thereto, included elsewhere in this prospectus.

The unaudited pro forma condensed consolidated financial statements are included for informational purposes only and do not purport to reflect our results of operations or financial position that would have occurred had the Acquisition Transaction and Conversion occurred on the dates assumed, and they therefore should not be relied upon as being indicative of our results of operations or financial position had the Conversion or the Acquisition Transaction occurred on the dates assumed. The unaudited condensed consolidated pro forma financial statements are also not a projection of our results of operations or financial position for any future period or date.

 

 

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Table of Contents

Unaudited Pro Forma Condensed Consolidated Statements of Operations

 

     Year Ended December 31, 2010  
     Predecessor      Conversion
Adjustments
     Acquisition
Transaction
Adjustments(a)
     Pro Forma  
     (In thousands, except per share information)  

Revenues

     $1,286,599         $—           $—           $1,286,599   

Costs of revenues, excluding depreciation, depletion and amortization

     641,783         —           —           641,783   

Selling and administrative costs

     136,299         —           —           136,299   

Depreciation, depletion and amortization

     117,976         —           161,765(b)         279,741   
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from operations

     390,541         —           (161,765)         228,776   

Interest expense, net, and other income (expense)

     (18,611)         —           (97,585)(c)         (116,196)   
  

 

 

    

 

 

    

 

 

    

 

 

 

Income before income taxes

     371,930         —           (259,350)         112,580   

Income taxes

     3,254         137,550(d)         (98,136)(d)         42,668   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income

     $368,676         $(137,550)         $(161,214)         $69,912   
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic and diluted net income per share

           

Weighted average number of shares outstanding:

           

Basic

           

Diluted

           

 

See footnotes below

           

 

    Six Months Ended June 30, 2011  
    Historical        
    Predecessor
(January 1
through

May 5, 2011)
         Successor
(May 6
through
June 30, 2011)
    Conversion
Adjustments
    Acquisition
Transaction
Adjustments(a)
    Pro Forma  
               (In thousands, except per share information)  

Revenues

  $ 729,365          $ 366,997      $ —        $ —        $ 1,096,362   

Costs of revenues, excluding depreciation, depletion and amortization

    365,480            245,763        —          (52,723 )(e)      558,520   

Selling and administrative costs

    88,695            30,001        —          (34,366 )(f)      84,330   

Depreciation, depletion and amortization

    52,553            49,134        —          46,294 (b)      147,981   
 

 

 

       

 

 

   

 

 

   

 

 

   

 

 

 

Income from operations

    222,637            42,099        —          40,795        305,531   

Interest expense, net, and other income (expense)

    (15,282         (22,533     —          (33,339 )(c)      (71,154
 

 

 

       

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

    207,355            19,566        —          7,456        234,377   

Income taxes

    2,051            730        83,354 (d)      2,928 (d)      89,063   
 

 

 

       

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 205,304          $ 18,836      $ (83,354   $ 4,528      $ 145,314   
 

 

 

       

 

 

   

 

 

   

 

 

   

 

 

 
Basic and diluted net income per share            

Weighted average number of shares outstanding:

           

Basic

           

Diluted

           

 

See footnotes below

           

 

 

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Table of Contents

Unaudited Pro Forma Condensed Consolidated Balance Sheet

 

     June 30, 2011  
     Historical
Successor
     Conversion
Adjustments
     Pro Forma  
     (In thousands)  

Total current assets

   $ 719,291       $ 6,463 (d)     $ 725,754   

Total non-current assets

     5,150,357         —           5,150,357   
  

 

 

    

 

 

    

 

 

 

Total assets

   $ 5,869,648       $ 6,463       $ 5,876,111   
  

 

 

    

 

 

    

 

 

 

Total current liabilities

   $ 257,570       $ 10,471 (d)     $ 268,041   

Deferred tax liabilities, net

     —           226,059 (d)       226,059   

Long-term notes, net of current portion

     2,038,241         —           2,038,241   
  

 

 

    

 

 

    

 

 

 

Total liabilities

     2,295,811         236,530         2,532,341   

Owners’ equity

     3,573,837         (230,067      3,343,770   
  

 

 

    

 

 

    

 

 

 

Total liabilities and owners’ equity

   $ 5,869,648       $ 6,463       $ 5,876,111   
  

 

 

    

 

 

    

 

 

 

 

(a) Reflects the Acquisition Transaction which was accounted for as a business combination and is reflected in the pro forma financial statements as if the Acquisition Transaction had occurred on January 1, 2010. These pro forma adjustments reflect the estimated allocation of the purchase price to the pro rata fair value of tangible and intangible assets and liabilities as of the acquisition date. In calculating these pro forma adjustments, the purchase consideration has been allocated on a preliminary basis and therefore, may be subject to adjustment. We will finalize the amounts recognized as information necessary to complete the analysis is obtained. See Note 3 to our unaudited interim consolidated financial statements included elsewhere in this prospectus.
(b) Reflects the increased depreciation, depletion and amortization expense as if we had recorded the acquisition date fair values of our fixed assets and intangible assets as of January 1, 2010.
(c) Reflects the increased interest expense as a result of (i) the entry into our $1.5 billion senior secured term loan to finance a portion of the purchase price in the Acquisition Transaction and (ii) amortization of a $39.2 million premium recorded in accordance with acquisition accounting requirements associated with a fair market value adjustment on our senior notes which yielded above market interest rates at the closing of the Acquisition Transaction. The senior secured term loan bears interest at a rate per annum equal to LIBOR, plus an applicable margin based on our leverage, for which the effective interest rate used in calculating pro forma interest expense was 6.9%.
(d) Reflects adjustments to give effect to the Conversion for the periods presented. Prior to the Conversion, we have been treated as a partnership for federal income tax purposes and therefore have not directly paid income taxes on our income nor have we benefitted from losses. Instead, our income and other tax attributes have been passed through to our owners for federal and, where applicable, state income tax purposes. Following the Conversion, we will be treated as a corporation for tax purposes and will be required to pay federal and state income taxes. The unaudited pro forma condensed consolidated statements of operations reflect: (1) the tax expense we would have incurred had we been subject to tax as a corporation in the historical periods presented (those pro forma adjustments being presented in the Conversion column), and (2) the tax effect of the acquisition accounting adjustments (those pro forma adjustments being presented in the Acquisition Transaction column). The pro forma balance sheet reflects deferred taxes related to the differences in the book and tax carrying values of our assets and liabilities as of June 30, 2011. As required under GAAP, upon completion of our Conversion, the impact of recognizing deferred tax assets and liabilities will be recorded as a charge to income in the fiscal quarter in which the Conversion occurs. As of June 30, 2011, the amount of the charge would have been $230 million. The impact of recognizing deferred tax assets and liabilities has been excluded from our unaudited pro forma condensed consolidated statements of operations because it is not expected to have a continuing impact.
(e) Reflects the removal of non-recurring additional costs of revenues that we recorded in May and June 2011 resulting from the allocation of fair value to our inventories as of the date of the Acquisition Transaction.
(f) Reflects the removal of transaction costs (such as legal and other professional fees) and employee benefit costs directly related to the Acquisition Transaction that were incurred by our predecessor. These employee benefit costs were the result of accelerated vesting of employee ownership-based compensation and bonus awards due to pre-existing change of control provisions triggered by the Acquisition Transaction.

 

 

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RISK FACTORS

An investment in our common stock involves risks. You should carefully consider the risks described below before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Relating to Our Business

Our business is cyclical and depends on spending and drilling activity by the onshore oil and natural gas industry in the United States, and the level of such activity is volatile. Our business has been, and may continue to be, adversely affected by industry conditions that are beyond our control.

Our business is cyclical, and we depend on our customers’ willingness to make expenditures to explore for, develop and produce oil and natural gas in the United States. Our customers’ willingness to undertake these activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, including:

 

   

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

 

   

domestic and foreign supply of and demand for oil and natural gas;

 

   

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

 

   

available pipeline, storage and other transportation capacity;

 

   

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

 

   

the expected rates of decline in production from existing and prospective wells;

 

   

the discovery rates of new oil and natural gas reserves;

 

   

federal, state and local regulation of hydraulic fracturing and other oilfield service activities, E&P activities and mining activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;

 

   

the availability, capacity and cost of disposal and recycling services for used hydraulic fracturing fluids;

 

   

the availability of water resources and suitable proppants in sufficient quantities for use in hydraulic fracturing operations;

 

   

political instability in oil and natural gas producing countries;

 

   

advances in exploration, development and production technologies or in technologies affecting energy consumption;

 

   

the price and availability of alternative fuels and energy sources; and

 

   

uncertainty in capital and commodities markets and the ability of oil and natural gas producers to raise equity capital and debt financing.

 

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The level of E&P activity in the United States is volatile. Changes in current or anticipated future prices for crude oil and natural gas are a primary factor affecting capital spending and drilling activity by E&P companies, and decreases in capital spending and drilling activity can cause rapid and material declines in demand for fracturing services. A reduction in the activity levels of our customers would cause a decline in the demand for our services and could adversely affect the prices that we can charge or collect for our services. In addition, any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and, therefore, would affect demand for the services we provide. A material decline in oil and natural gas prices or drilling activity levels or sustained lower prices or activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flow.

A substantial portion of our revenues in 2010 and the first six months of 2011 was derived from our activities in the Haynesville Shale. Drilling activity in the Haynesville Shale has been, and may be further, reduced due to lower natural gas prices, which could adversely impact our revenues.

In 2009, declines in prices for oil and natural gas, together with adverse changes in the capital and credit markets, caused many E&P companies to sharply reduce capital expenditure budgets and drilling activity. This trend resulted in a significant decline in demand for our services, had a material negative impact on the prices we were able to charge our customers and adversely affected our equipment utilization and results of operations. We were in default with respect to certain covenants under our prior revolving credit facility as of December 31, 2009, which we resolved by entering into an amendment and forbearance agreement in January 2010 and an amended and restated facility in May 2010. This facility was terminated in November 2010. Future cuts in spending levels or drilling activity could have similar adverse effects on our results of operations and financial condition, and such effects could be material.

Any future decreases in the rate at which oil or natural gas reserves are discovered or developed, or any increase in in-house fracturing capabilities by E&P companies, could decrease the demand for our services.

Reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves, in our market areas, whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, could have a material adverse impact on our business even in a stronger oil and natural gas price environment. In addition, some E&P companies have begun performing hydraulic fracturing on their wells using their own equipment and personnel. Any increase in the development and utilization of in-house fracturing capabilities by E&P companies could decrease the demand for our services and have a material adverse impact on our business.

We are subject to federal, state and local laws and regulations regarding issues of health, safety and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business.

Our operations are subject to stringent federal, state and local laws and regulations relating to, among other things, protection of natural resources, wetlands, endangered species, the environment, health and safety, waste management, waste disposal and transportation of waste and other materials. Our operations pose risks of environmental liability, including leakage from our operations to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. Therefore, in some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties, expenditures for remediation or other corrective measures, and claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include the assessment of administrative, civil or criminal penalties, revocation of permits, temporary or permanent cessation

 

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of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition and results of operations. Additionally, an increase in regulatory requirements on oil and gas exploration and completion activities could significantly delay or interrupt our operations.

If we do not perform in accordance with government, industry or our own safety standards, we could lose business from our customers, many of whom have an increased focus on safety issues as a result of recent incidents, such as the Macondo Well event in the Gulf of Mexico, and governmental initiatives on safety and environmental issues related to E&P activities. The EPA has announced that the energy extraction sector is one of the sectors designated for increased enforcement over the next three to five years.

Additionally, the EPA regulates air emissions from certain off-road diesel engines that are used by us to power equipment in the field. Under these Tier IV regulations, we are required to retrofit or retire certain engines, and we are limited in the number of non-compliant off-road diesel engines we can purchase. Tier IV engines are costlier and are not yet widely available. Until Tier IV-compliant engines that meet our needs are available, these regulations could limit our ability to acquire a sufficient number of diesel engines to expand our fleet and to replace existing engines as they are taken out of service. Further, the Tier IV regulations may result in increased costs as we continue to grow.

Laws protecting the environment generally have become more stringent over time and we expect them to continue to do so, which could lead to material increases in our costs for future environmental compliance and remediation. See “Business—Environmental Regulation” for more information on the environmental laws and government regulations that are, or may be in the future, applicable to us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could restrict or make more difficult our hydraulic fracturing operations, could increase our operating costs or could result in the disclosure of proprietary information resulting in competitive harm.

On March 15, 2011, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) were introduced in the United States Senate and House of Representatives. If passed, the FRAC Act would significantly alter regulatory oversight of hydraulic fracturing. Currently, unless the fracturing fluid used in the hydraulic fracturing process contains diesel fuel, hydraulic fracturing operations are exempt from the definition of “underground injection” subject to regulation under Underground Injection Control (“UIC”) program in the federal Safe Drinking Water Act. The FRAC Act would remove this exemption and define hydraulic fracturing affirmatively as “underground injection” subject to regulation under the UIC program. The FRAC Act would also require persons conducting hydraulic fracturing, such as us, to disclose the chemical constituents, but not the proprietary formulas (except in cases of emergency), of their fracturing fluids to a regulatory agency. This Act would make the information public via the internet, which could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. At this time, it is not clear what action, if any, the United States Congress will take on the FRAC Act.

The United States Environmental Protection Agency (the “EPA”) has asserted federal regulatory authority over the injection of fracturing fluid containing diesel fuel under the UIC program and has announced its intent to draft guidance documents for permitting authorities and the industry on the process of obtaining a UIC permit for the injection of fracturing fluids containing diesel fuel during hydraulic fracturing. Some public statements by EPA officials suggest that the EPA considers the past injection of fracturing fluids containing diesel fuel without an UIC permit to be a violation of the Safe Drinking Water Act. Litigation is pending that challenges the validity of the EPA’s position. In addition, at the direction of Congress the EPA is currently undertaking a study of the potential impacts of hydraulic fracturing on drinking water and groundwater. The EPA has announced its intent to issue an interim report on the study in late 2012 and a final report in late 2014.

 

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Depending on its results, the EPA study could spur further initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or otherwise. Similarly, other federal and state studies, such as those currently being conducted by the Secretary of Energy’s Advisory Board and the New York Department of Environmental Conservation, may recommend or mandate additional requirements or restrictions on hydraulic fracturing operations.

If the FRAC Act or similar legislation becomes law, or the EPA or another federal agency asserts jurisdiction over certain aspects of hydraulic fracturing operations, an additional level of regulation could be established 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, several states in which we conduct hydraulic fracturing operations such as Louisiana, Pennsylvania, New Mexico, and Texas, have considered, or are considering, legislation or regulations requiring the disclosure of chemicals used during hydraulic fracturing operations or are taking action to restrict or further regulate hydraulic fracturing operations in certain jurisdictions. At this time, it is not possible to estimate the potential impact on our business of these state actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing. Compliance or the consequences of any failure to comply by us could have a material adverse effect on our business, financial condition and operational results. Additionally, 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.

We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.

Our services are subject to inherent hazards that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of operations. Litigation arising from an accident at a location where our services are provided may cause us to be named as a defendant in lawsuits asserting potentially large claims. We maintain customary insurance to protect our business against these potential losses but such insurance may not be adequate to cover our liabilities. Further, our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. In addition, insurance may not be available in the future at rates that we consider reasonable and commercially justifiable. As a result, we could become subject to material uninsured liabilities that could have a material adverse effect on our business, financial condition or results of operations.

The loss of key executives would adversely affect our ability to effectively finance and manage our business and obtain and retain customers.

We are dependent upon the efforts and skills of our executives, including Marcus C. Rowland, our Chief Executive Officer, to manage, finance and grow our business and to obtain and retain customers. In addition, our development and expansion will require additional experienced management, operations and technical personnel. We cannot assure you that we will be able to identify and retain these employees. Also, the loss of the services of one or more of our key executives could increase our exposure to the other risks described in this “Risk Factors” section. We do not maintain key man insurance on any of our personnel.

Our industry is highly competitive, with intense price competition, which may intensify as our competitors expand their operations.

The markets in which we operate are highly competitive, and business is traditionally awarded on a competitive bid basis. The competitive environment has intensified as recent mergers among E&P companies have reduced the number of available customers. Other companies that offer hydraulic fracturing services are larger than we are, offer a broader range of products and services than we do and have resources that are significantly greater than ours. In addition, we believe that our competitors are pursuing plans to increase their horsepower and fleets in the near term. These competitors may be better able to withstand industry downturns,

 

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compete on the basis of price and acquire new equipment and technologies, all of which could affect our revenues and profitability. Moreover, other companies may also become vertically integrated, potentially lowering their costs and increasing their margins. Further, we believe one source of our competitive advantage is the durability of our fluid ends, which advantage is most pronounced in the most demanding shale formations such as the Haynesville Shale. To the extent drilling activity moves to less demanding shale formations, competition may increase. This competition may cause our business to suffer. We believe that competition for contracts will continue to be intense in the foreseeable future.

The proppant market is highly competitive.

The proppant market is highly competitive. We are aware of numerous new sand mines and coating plants that have either been constructed, are under construction or have been permitted. The entry of additional competitors into the market to supply proppants could have a material adverse effect on our results of operations and financial condition because an increase in the supply of or a decrease in the price for proppants could reduce the margins we currently earn on our proppants.

If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share.

Because of the technical nature of our business, we have trade secrets that we believe provide us with a competitive advantage, including proprietary designs we use in manufacturing our hydraulic pumps and other equipment and formulas we use in developing and producing the chemicals we use in fracturing fluids. Moreover, although we have filed several patent applications, we do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology, our competitive advantage would be diminished. We also cannot assure you that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes.

A third party may claim we infringed upon its intellectual property rights, and we may be subjected to costly litigation.

Our equipment and manufacturing operations may unintentionally infringe upon the patents or trade secrets of a competitor or other company that uses proprietary components or processes in its manufacturing operations, and that company may have legal recourse against our use of its protected information. If this were to happen, these claims could result in legal and other costs associated with litigation, and may distract our management team from its day-to-day running of our business. If found to have infringed upon protected information, we may have to make royalty payments in order to continue using that information, which could substantially increase the costs previously associated with certain products or services, or we may have to discontinue use of the information altogether. In the latter case, we may no longer be able to use the product or to provide the service associated with such protected information.

Delays in obtaining permits by our customers for their operations or by us for our operations could impair our business.

In most states, our customers are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities, including hydraulic fracturing. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. The requirements for such permits vary depending on the location where such drilling and completion activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued and the conditions which may be imposed in connection with the granting of the permit. In some jurisdictions, such as New York State and within the

 

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jurisdiction of the Delaware River Basin Commission, certain regulatory authorities have delayed or suspended the issuance of permits while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. Permitting delays, an inability to obtain new permits or revocation of our or our customers’ current permits could cause a loss of revenue and potentially have a materially adverse effect on our operations.

We are also required to obtain federal and state permits in connection with our sand mining and processing activities. These permits impose certain conditions on our operations, some of which require significant expenditures for filtering or other emissions control devices at each of our processing facilities. Changes in these requirements could increase our costs or limit the amount of sand we can process. Any such changes could have a material adverse effect on our financial condition and results of operations.

We are dependent on a few customers operating in a single industry. The loss of one or more significant customers could adversely affect our financial condition and results of operations.

Our customers are engaged in the E&P business in the United States. Historically, we have been dependent upon a few customers for a significant portion of our revenues. In 2009, 2010 and the first six months of 2011, our three largest customers generated more than 53%, 38% and 36% respectively, of our consolidated revenues. Chesapeake has historically been one of our largest customers, and for the six months ended June 30, 2011, was our largest customer, representing 15.9% of our consolidated gross revenues.

Our business, financial condition and results of operations will be materially adversely affected if one or more of our significant customers fails to pay us or ceases to engage us for our services on favorable terms or at all. Although we do have contracts for multiple projects with certain of our customers, most of our services are provided on a project-by-project basis.

Additionally, the E&P industry is characterized by frequent consolidation activity, and two of our major customers recently have been acquired by larger companies. Changes in ownership of our customers may result in the loss of or reduction in business from those customers.

Growth in our business could strain our resources and increase our operating expenses.

We have experienced rapid growth since we began providing hydraulic fracturing services to E&P companies in 2002, and we are currently expanding our operations to take advantage of favorable market conditions. This growth has at times placed a strain on our managerial and operational resources. Our growth is requiring us, and any future growth may require us, among other things, to:

 

   

raise additional capital;

 

   

expand and improve our operational and financial procedures, infrastructure, systems and controls;

 

   

hire additional management, accounting or other personnel;

 

   

improve our financial and management information systems;

 

   

expand, train and manage a larger workforce; and

 

   

improve the coordination among our operating, sales and marketing, financial, accounting and management personnel.

Our inability to manage growth effectively or to maintain the quality of our services could have a material adverse effect on our business, financial condition or results of operations.

 

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Changes in trucking regulations may increase our costs and negatively impact our results of operations.

For the transportation and relocation of our hydraulic fracturing equipment, sand and chemicals, we operate trucks and other heavy equipment. We therefore are subject to regulation as a motor carrier by the United States Department of Transportation and by various state agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as by requiring changes in fuel emissions limits, the hours of service regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters. On May 21, 2010, President Obama signed an executive memorandum directing the National Highway Traffic Safety Administration and the Environmental Protection Agency to develop new, stricter fuel efficiency standards for medium- and heavy-duty trucks. On October 25, 2010, the NHTSA and the EPA proposed regulations that would regulate fuel efficiency and greenhouse gas emissions beginning in 2014. Associated with this ruling, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, decrease in the residual value of these vehicles and an increase in operating expenses. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. We cannot predict whether, or in what form, any legislative or regulatory changes applicable to our trucking operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations.

New technology may cause us to become less competitive.

The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent protection. Although we believe our equipment and processes currently give us a competitive advantage, as competitors and others use or develop new or comparable technologies 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 that may allow them to enjoy technological advantages and implement new technologies before we can. We cannot be certain that we will be able to implement new technologies or products on a timely basis or at an acceptable cost. Thus, limits on our ability to effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition or results of operations.

Increased labor costs or the unavailability of skilled workers could hurt our operations.

Companies in our industry, including us, are dependent upon the available labor pool of skilled employees. We compete with other hydraulic fracturing businesses, other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. We cannot assure you that labor costs will not increase. Any increase in our operating costs could have a material adverse effect on our business, financial condition and results of operations.

Although none of our employees are currently subject to a collective bargaining agreement, a small group of employees at our sand processing plant in Oakdale, Wisconsin recently sought to certify a union. This matter is currently pending with the National Labor Relations Board. Unions may attempt to organize all or part of our employee base. In addition to potentially increasing our labor costs, responding to such attempts may distract management and employees and may have a negative financial impact on our business as a whole.

 

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Shortages or increases in the costs of products or equipment we use in our operations or parts we use in the manufacture of our equipment could adversely affect our operations in the future.

We do not have long-term contracts with the third-party suppliers of many of the products that we use in large volumes in our operations, including many parts we use in the fabrication and assembly of our hydraulic fracturing units and hydraulic pumps, a portion of the chemicals we use in fracturing fluids and the fuel we use in our equipment and vehicles. During periods in which fracturing services are in high demand, the availability of the key products used in our industry decreases and the price of such products increases. During such periods in the past, we have experienced delays in obtaining certain parts that we use in fabricating and assembling our hydraulic fracturing units. We are dependent on a small number of suppliers for certain parts that are in high demand in our industry. For example, all the diesel engines we use in our hydraulic fracturing units are manufactured by Caterpillar Inc., Cummins Inc. or MTU Detroit Diesel, and all the transmissions we use in our hydraulic fracturing units are manufactured by Caterpillar Inc. or Twin Disc, Inc. Our reliance on a small number of suppliers could increase the difficulty of obtaining such parts in the event of shortage of those parts in our industry. In addition, rising diesel fuel prices have had a significant impact on our expenses, and adversely impacted our earnings, in some periods. Any increase in our operating costs, or difficulty in obtaining enough materials for our operations, could have a material adverse effect on our business, financial condition or results of operations.

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

Our activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operating activities, borrowings under bank credit agreements, equity investments by Chesapeake, equipment financings and borrowings by our subsidiaries. If our cash flow from operating activities and borrowings under our revolving credit facility are not sufficient to fund our capital expenditure budget, we would be required to fund these expenditures through debt or equity or other methods of financing. If debt and equity capital are not available or are not available on economically attractive terms, we would be required to curtail our capital spending, and our ability to grow our business and sustain or improve our profits may be adversely affected. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Expenditures.”

We are a holding company dependent on our subsidiaries to conduct our operations.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. As a result, our ability to repay our indebtedness and other obligations depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us is restricted by, among other things, the terms of any indebtedness of our subsidiaries, including the indenture governing our senior notes and the terms of our revolving credit facility, and applicable laws and regulations.

Severe weather could have a material adverse impact on our business.

Our business could be materially adversely affected by severe weather. For example, oil and natural gas operations of our customers located in Louisiana and parts of Texas may be adversely affected by hurricanes and tropical storms and those in the northern and northeastern regions of the United States may be adversely affected by seasonal weather conditions. Our operations in arid regions can be affected by droughts and other lack of access to water used in our hydraulic fracturing operations. Adverse weather can also directly impede our own operations. Repercussions of severe weather conditions may include:

 

   

curtailment of services;

 

   

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

 

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

 

   

interference with sand mining and processing operations; and

 

   

loss of productivity.

These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters also adversely affect the demand for our services by decreasing the demand for natural gas.

The application of acquisition accounting could result in further changes in the recorded value of our assets, and goodwill and intangible asset impairment analysis may result in charges, which may be significant.

We recorded the Acquisition Transaction using the acquisition accounting method, under which the assets acquired and liabilities assumed were recorded at their estimated fair values as of May 6, 2011. Even though our operations did not change significantly due to the Acquisition Transaction, the expenses related to the changes in our basis of accounting do affect certain expenses recognized following the Acquisition Transaction. As a result, our financial results for periods after the Acquisition Transaction are not comparable to our financial results for periods prior to the Acquisition Transaction. Further, our estimates of fair value as of the acquisition date are not yet finalized and are subject to change.

Following the Acquisition Transaction, we recorded the excess of the purchase price over tangible assets, identifiable intangibles and assumed liabilities in the amount of $2.7 billion as goodwill, which is substantially higher than the goodwill in our financial statements prior to the Acquisition Transaction. We may be required to write-down the carrying value of goodwill based on the value of our business in the future. If we conclude that there is a significant impairment of our goodwill as a result of any impairment analysis, we would be required to record corresponding non-cash impairment charges, which could negatively and materially affect our results of operations and the market price of our common stock.

Our indebtedness may limit our financial flexibility.

As of June 30, 2011, we had approximately $2.1 billion in principal amount of total long-term indebtedness outstanding, and our net indebtedness represented approximately 36.6% of our total book capitalization. On a pro forma basis after giving effect to the closing of this offering and the application of the estimated net proceeds of this offering to repay borrowings under our senior secured term loan as described in “Use of Proceeds,” we would have had total long-term indebtedness of $             outstanding as of June 30, 2011. See “Capitalization.”

Our indebtedness affects our operations in several ways, including the following:

 

   

a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

 

   

we may be at a competitive disadvantage as compared to similar companies that have less debt;

 

   

the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments, including investments in international joint ventures, make capital expenditures and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

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additional financing in the future for working capital, capital expenditures, acquisitions, general corporate and other purposes may have higher costs and more restrictive covenants; and

 

   

a lowering of the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing.

We may incur additional debt, including secured indebtedness, in order to continue growing our business. A higher level of indebtedness increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and finance, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offering our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital. In addition, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness, which could adversely affect our business, financial condition and results of operations.

International expansion will subject us to the economic, political and other risks of doing business in certain foreign countries.

One of our strategies is to expand internationally. Any such expansion will expose us to risks of international operations, including:

 

   

exposure to foreign currency exchange rates, currency devaluations and exchange controls;

 

   

war, civil unrest or significant political instability;

 

   

restrictions on repatriation of income or capital;

 

   

confiscatory taxation, nationalization or other government actions with respect to our assets located in the markets where we operate;

 

   

restrictive government regulation and bureaucratic delays; and

 

   

compliance with additional legal and regulatory requirements, including the Foreign Corrupt Practices Act.

Risks Relating to the Offering and Our Common Stock

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active liquid trading market for our common stock may not develop and our stock price may be volatile.

Prior to this offering, our equity securities were not traded on any market. An active and liquid trading market for our common stock may not develop or be maintained after this offering. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us and representatives of the underwriters, based on numerous factors that we discuss in the “Underwriting” section of this prospectus, and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in the offering.

 

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The following factors, among others, could affect our stock price:

 

   

our operating and financial performance;

 

   

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

 

   

changes in revenue or earnings estimates or publication of reports by equity research analysts;

 

   

speculation in the press or investment community;

 

   

sales of our common stock by us or our stockholders, or the perception that such sales may occur;

 

   

general market conditions, including fluctuations in actual and anticipated future commodity prices; and

 

   

domestic and international economic, legal and regulatory factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

Purchasers of common stock in this offering will experience immediate and substantial dilution.

Based on an assumed initial public offering price of $             per share (the midpoint of the price range set forth on the cover page of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $             per share in the pro forma as adjusted net tangible book value per share of our common stock from the initial public offering price. Our pro forma as adjusted net tangible book value as of                     , 2011 after giving effect to this offering would be $             per share. See “Dilution” for a complete description of the calculation of net tangible book value.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management. We may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we will have to comply with numerous laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, the Dodd-Frank Wall Street Reform and Consumer Protection Act, related regulations of the U.S. Securities and Exchange Commission (“SEC”) and the requirements of the New York Stock Exchange (the “NYSE”), with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

 

   

institute a more comprehensive compliance function;

 

   

expand, evaluate and maintain our system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board (the “PCAOB”);

 

   

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

 

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comply with corporate governance and other rules promulgated by the NYSE;

 

   

prepare and file annual, quarterly and other periodic public reports in compliance with the federal securities laws;

 

   

prepare proxy statements and solicit proxies in connection with annual meetings of our stockholders;

 

   

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

 

   

establish an investor relations function.

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 such 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.

We may be unsuccessful in implementing required internal controls over financial reporting.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require 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 will not be 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.

We are in the process of evaluating our internal control systems to allow management to report on, and our independent auditors to assess, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and PCAOB rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that materially affect, or are reasonably likely to materially affect, internal controls over financial reporting. The PCAOB has defined a material weakness as a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented, or detected and subsequently corrected, on a timely basis.

Our efforts to develop and maintain effective 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. Any failure to remediate future deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanctions or investigations by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

 

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We do not intend to pay dividends on our common stock and, consequently, you will have an opportunity to achieve a return on your investment only if the price of our stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently limited in our ability to make cash distributions to stockholders pursuant to the terms of our senior secured term loan, our revolving credit facility and the indenture governing our senior notes. Consequently, your only opportunity to achieve a return on your investment in us will be if the market price of our common stock appreciates, which may not occur, and you sell your shares at a profit. There is no guarantee that the price of our common stock that will prevail in the market after this offering will ever exceed the price that you pay. See “Dividend Policy.”

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings and may also issue securities convertible into our common stock. After the completion of this offering, we will have                      outstanding shares of common stock. This number includes                  shares that we and the selling stockholder are selling in this offering (assuming no exercise of the underwriters’ over-allotment option), which may be resold immediately in the public market. Following the completion of this offering, certain of our affiliates will own the balance of our outstanding shares of common stock, consisting of                  shares or approximately     % of total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriting,” but may be sold into the market in the future.

Following this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of             shares of our common stock issued or reserved for issuance under our 2011 Long-Term Incentive Plan. Subject to the satisfaction of vesting conditions, shares registered under that registration statement will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our certificate of incorporation and bylaws, as well as Delaware law, will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Some provisions in our certificate of incorporation and bylaws, as well as Delaware statutes, may have the effect of delaying, deferring or preventing a change in control. These provisions, including those providing for the possible issuance of shares of our preferred stock and the right of the board of directors to amend the bylaws, may make it more difficult for other persons, without the approval of our board of directors, to make a tender offer or otherwise acquire a substantial number of shares of our common stock or to launch other takeover attempts that a stockholder might consider to be in his or her best interest. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock. See “Description of Capital Stock—Anti-Takeover Effects of Provisions of Delaware Law, Our Certificate of Incorporation and Our Bylaws.”

 

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Our investor group will collectively retain a majority interest in us and have the ability to control all major company decisions, and their interests may conflict with the interests of our other stockholders.

After this offering, our investor group will indirectly own and control a majority of our outstanding common stock and therefore will have the power to control our affairs and policies. See “Principal and Selling Stockholders.” They will also control the election of the board of directors, the appointment of our management, the entry into business combinations or dispositions and other extraordinary transactions. Chesapeake, which will own     % of our outstanding common stock immediately following this offering, has historically been one of our largest customers and for the six months ended June 30, 2011, was our largest customer, representing 15.9% of our consolidated gross revenues. The interests of our investor group, including Chesapeake, could conflict with your interests.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this prospectus constitute forward-looking statements. You should not place undue reliance on these statements. These forward-looking statements include statements that reflect the views of our senior management with respect to our current expectations, assumptions, estimates and projections about Frac Tech and our industry. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “anticipate,” “plan,” “continue,” “estimate,” “expect,” “may,” “intend,” “could,” “should,” “believe” and similar expressions. Forward-looking statements address matters that involve risks and uncertainties that could cause actual results or events to differ materially from those anticipated in these forward-looking statements as of the date of this report. We believe that these risks and uncertainties include the following:

 

   

general economic conditions;

 

   

the demand for hydraulic fracturing and other stimulation services during completion of oil and natural gas wells or during post-completion recovery enhancement efforts;

 

   

volatility in market prices for oil and natural gas and the effect of this volatility on the demand for oilfield services generally;

 

   

regional competition;

 

   

liabilities and risks, including environmental liabilities and risks, inherent in oil and natural gas operations;

 

   

our ability to comply with the financial covenants and other restrictive covenants in our debt agreements;

 

   

sourcing, pricing and availability of raw materials, component parts, equipment, supplies, facilities and skilled personnel;

 

   

our ability to integrate technological advances and match advances of our competition;

 

   

the availability of capital;

 

   

uncertainties in weather and temperature affecting the duration of the service periods and the activities that can be completed;

 

   

dependence on a limited number of major customers; and

 

   

changes in legislation and the regulatory environment.

The foregoing factors should not be construed as exhaustive and should be read together with the other cautionary statements included in this prospectus, including the information presented under the heading “Risk Factors.” If one or more events related to these or other risks and uncertainties materialize, or if our underlying assumptions prove to be incorrect, our actual results may differ materially from what we anticipate. Except as may be required by law, we do not intend, and do not assume any obligation, to update any forward-looking statements.

 

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USE OF PROCEEDS

We will receive net proceeds of approximately $         million from our sale of shares of our common stock in this offering, assuming an initial public offering price of $         per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated expenses and underwriting discounts of approximately $         million. If the over-allotment option that we have granted to the underwriters is exercised in full, we estimate that the net proceeds to us will be approximately $         million. We will not receive any proceeds from the sale of shares by the selling stockholder, including any shares subject to the over-allotment option that it has granted to the underwriters. The selling stockholder will be responsible for the underwriting discounts with respect to its shares sold in the offering, but we will pay all other expenses related to this offering, including legal fees and other expenses, incurred by the selling stockholder.

We intend to use all of the net proceeds from this offering to repay outstanding borrowings under our senior secured term loan. Amounts borrowed under the senior secured term loan, which matures on May 6, 2016, bear interest at a rate equal to LIBOR plus an applicable margin based on our leverage. As of June 30, 2011, the rate of interest on outstanding borrowings under our senior secured term loan was 6.25% per annum. The senior secured term loan was used to finance the Acquisition Transaction.

DIVIDEND POLICY

We currently intend to retain future earnings, if any, for use in the operation and expansion of our business and, therefore, do not anticipate paying any cash dividends in the foreseeable future following this offering. However, our board of directors, in its discretion, may authorize the payment of dividends in the future. Any decision to pay future dividends will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our senior secured term loan, our revolving credit facility and the indenture governing our senior notes contain covenants that restrict our ability to make distributions to our stockholders. See “Description of Certain Indebtedness.”

 

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CAPITALIZATION

The following table sets forth our capitalization as of June 30, 2011:

 

   

on an actual basis, and

 

   

on an as adjusted basis to give effect to:

 

   

the consummation of our Conversion from a limited liability company to a corporation as described in “History and Conversion,” and

 

   

the closing of this offering and the application of the estimated net proceeds of this offering to repay borrowings under our senior secured term loan as described in “Use of Proceeds.”

You should read this table in conjunction with our consolidated financial statements and the notes to our consolidated financial statements included elsewhere in this prospectus.

 

     As of June 30, 2011  
     Actual      As Adjusted  
    

(Unaudited)

 
    

(In thousands)

 

Cash and cash equivalents

   $ 216,979       $                
  

 

 

    

 

 

 

Long-term debt, including current maturities(1)

     

Senior secured term loan

     1,454,219      

Senior notes

     588,257      

Other debt(2)

     20,630      
  

 

 

    

 

 

 

Total debt

     2,063,106      

Owners’ equity/stockholders’ equity

     

Common stock

     —        

Additional paid-in capital

     —        

Preferred equity interests

     —        

Common equity interests

     3,573,837      
  

 

 

    

 

 

 

Total owners’ equity/stockholders’ equity

     3,573,837      
  

 

 

    

 

 

 

Total capitalization

   $ 5,636,943       $     
  

 

 

    

 

 

 

 

(1) On August 5, 2011, we entered into a $100 million revolving credit facility. We currently have no outstanding borrowings under that facility.
(2) Consists primarily of term installment notes secured by certain of our assets. See Note 7 to our audited consolidated financial statements and Note 9 to our unaudited consolidated financial statements included elsewhere in this prospectus for additional information about our outstanding indebtedness.

 

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DILUTION

If you invest in our common stock, your interest will be diluted to the extent of the difference between the initial public offering price per share of our common stock and the pro forma as adjusted net tangible book value per share of our common stock after this offering. We calculate net tangible book value per share by dividing the net tangible book value (tangible assets less total liabilities) by the number of outstanding shares of common stock.

Our pro forma net tangible book value as of June 30, 2011 was approximately $         million, or $         per share of common stock, based on                  shares of common stock outstanding upon the closing of this offering. After giving effect to our Conversion and the sale of                  shares of common stock by us in this offering at an assumed initial public offering price of $         per share, less the estimated underwriting discounts and the estimated offering expenses payable by us, our pro forma as adjusted net tangible book value as of June 30, 2011, would be $         million, or $         per share. This represents an immediate increase in the pro forma net tangible book value of $         per share to existing stockholders and an immediate dilution of $         per share to investors purchasing shares in this offering. The following table illustrates this per share dilution:

 

Assumed initial public offering price per share

      $                

Pro forma net tangible book value per share as of June 30, 2011

   $                   

Increase per share attributable to this offering

     
  

 

 

    

Pro forma net tangible book value per share and this offering

     
     

 

 

 

Dilution per share to new investors in this offering

      $     
     

 

 

 

The following table shows, as of June 30, 2011, on a pro forma basis as described above, the difference between the number of shares of common stock purchased from us, the total consideration paid to us and the average price paid per share by existing stockholders and by new investors purchasing common stock in this offering:

 

     Shares Purchased     Total Consideration     Average
Price

per  Share
 
     Number     Percent     Amount      Percent    

Existing stockholders

          (1)                 $                             $                

New investors

                         
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Total

       100   $                      100   $                
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

 

(1) The total consideration and average price per share represents the consideration paid by the existing owners of our limited liability company units for their interests in Frac Tech International, LLC and is allocated on a pro forma basis to the shares of common stock that will be issued in respect to such interests in our Conversion prior to consummation of this offering.

Assuming the underwriters’ over-allotment option is exercised in full, sales by us in this offering will reduce the percentage of shares held by existing stockholders to     % and will increase the number of shares held by new investors to                     , or     %. This information is based on shares outstanding as of June 30, 2011. No material change has occurred to our equity capitalization since June 30, 2011.

Each $1.00 increase (decrease) in the assumed public offering price per share of common stock would increase (decrease) the pro forma deficit in net tangible book value by $         per share (assuming no exercise of the underwriters’ over-allotment option) and the dilution to investors in this offering by $         per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same.

 

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SELECTED CONSOLIDATED FINANCIAL DATA

The following selected consolidated financial information for each of the years in the three-year period ended December 31, 2010 is based on the audited consolidated financial statements of our predecessor included elsewhere in this prospectus. The selected consolidated financial information for the six months ended June 30, 2010 and the partial periods from January 1, 2011 through May 5, 2011 and May 6, 2011 through June 30, 2011 is based on our unaudited consolidated financial statements included elsewhere in this prospectus. The selected consolidated financial information for the year ended December 31, 2007 is based on the audited consolidated financial statements of our predecessor not included in this prospectus. The summary consolidated financial information for the year ended December 31, 2006 is based on the unaudited consolidated financial statements of our predecessor not included in this prospectus. In the opinion of our management, the interim financial information includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of our financial condition, results of operations and cash flows. The results for interim periods set forth below are not necessarily indicative of the results to be expected for the full year.

We recorded the Acquisition Transaction using the acquisition accounting method, under which the assets acquired and liabilities assumed were recorded at their estimated fair values as of May 6, 2011. The selected financial data below is presented on a “predecessor” basis for periods prior to May 6, 2011 and “successor” basis for periods beginning on or after May 6, 2011 to indicate the application of two bases of accounting and on a combined basis for the six month period ended June 30, 2011. Even though our operations did not change significantly due to the Acquisition Transaction, the expenses related to these changes in our basis of accounting affect certain expenses recognized in the successor period, thereby impacting the comparability of successor period and predecessor period financial information.

The information set forth below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and the related notes thereto included elsewhere in this prospectus.

 

    Predecessor          Successor     Combined  
    Year Ended December 31,     Six Months
Ended

June 30,
2010
    January  1
through

May 5,
2011
         May  6
through

June 30,
2011
    Six Months
Ended

June 30,
2011
 
    2006     2007     2008     2009     2010               
    (Unaudited)                             (Unaudited)     (Unaudited)          (Unaudited)     (Unaudited)  
    (In thousands)                   

Income Statement Information:

                     

Revenues

  $ 214,426      $ 362,462      $ 573,543      $ 389,230      $ 1,286,599      $ 451,874      $ 729,365          $ 366,997      $ 1,096,362   

Costs of revenues, excluding depreciation, depletion and amortization

    88,246        202,620        343,301        255,977        641,783        245,482        365,480            245,763        611,243   

Selling and administrative costs

    20,731        35,006        81,940        68,386        136,299        49,091        88,695            30,001        118,696   

Depreciation, depletion and amortization

    15,646        38,938        69,200        91,149        117,976        52,959        52,553            49,134        101,687   

Goodwill impairment

    —          —          5,971        —          —          —          —              —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Income (loss) from operations

    89,803        85,898        73,131        (26,282     390,541        104,342        222,637            42,099        264,736   

Interest expense, net

    (4,963     (13,467     (29,040     (15,945     (19,476     (11,529     (13,935         (22,829     (36,764

Other income (expense), excluding interest

    53        568        1,262        2,335        865        (66     (1,347         296        (1,051
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Income (loss) before income taxes

    84,893        72,999        45,353        (39,892     371,930        92,747        207,355            19,566        226,921   

Income taxes(1)

    2,421        1,248        1,994        347        3,254        1,685        2,051            730        2,781   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Net income (loss)

  $ 82,472      $ 71,751      $ 43,359      $ (40,239   $ 368,676      $ 91,062      $ 205,304          $ 18,836      $ 224,140   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Other Financial Information:

                     

Adjusted EBITDA(2)(unaudited)

  $ 105,449      $ 124,836      $ 148,302      $ 64,868      $ 518,844      $ 162,952      $ 309,556          $ 143,956      $ 453,512   

Capital expenditures

  $ 195,727      $ 292,469      $ 163,040      $ 61,777      $ 266,050      $ 47,689      $ 188,880          $ 90,236      $ 279,116   

 

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          Predecessor          Successor     Combined  
          Six
Months
Ended

June 30,
2010
    January  1
through

May 5,
2011
         May  6
through

June 30,
2011
    Six
Months
Ended

June 30,
2011
 
    Year Ended December 31,            
    2006     2007     2008     2009     2010               
                                                           

Operating Data—Unaudited:

                     

Number of wells fractured

    398        750        839        675        1,374        665        583            278        861   

Total fracturing stages

    *        *        *        4,786        9,916        4,253        5,086            2,506        7,592   

Average revenue per stage

    *        *        *      $ 81,327      $ 129,750      $ 105,155      $ 142,951          $ 140,754      $ 142,226   

Horsepower (end of period)

    213,750        678,250        779,500        802,000        996,250        802,000        1,194,000            1,312,750        1,312,750   

Number of fleets deployed (end of period)

    11        16        19        20        23        20        27            31        31   

 

* Unavailable

 

     June 30, 2011  
     Actual      As Adjusted(3)  
     (Unaudited)  
     (In thousands)  

Balance Sheet Information:

     

Cash and cash equivalents

   $ 216,979       $                

Fixed assets, net

   $ 1,378,227       $     

Total assets

   $ 5,869,648       $     

Long-term debt (including current portion)

   $ 2,063,106       $     

Owners’ equity

   $ 3,573,837       $     

 

(1) Consists primarily of State of Texas margin tax treated as income taxes for accounting purposes. Prior to our Conversion, we have been treated as a partnership for federal income tax purposes and therefore have not directly paid federal or state income taxes on our income.
(2) “Adjusted EBITDA” is a non-GAAP financial measure that we define as net income before interest, taxes, depreciation, depletion, amortization, gain or loss on sale of assets, ownership-based compensation and Acquisition Transaction costs, as further adjusted to add back amounts charged to income for goodwill impairment related to the discontinuance of the operations of a subsidiary in fiscal year 2008 and impairment of service equipment in fiscal year 2010. For additional information about this measure and a reconciliation of our Adjusted EBITDA to our net income, the most directly comparable GAAP financial measure, see footnote 2 to the table in “Prospectus Summary—Summary Consolidated Financial Information.”
(3) As adjusted to give effect to the closing of this offering and the application of the estimated net proceeds of this offering to repay borrowings under our senior secured term loan as described in “Use of Proceeds.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We are a leading provider of high-pressure hydraulic fracturing services to E&P companies in the United States. We have particular expertise in stimulating production of oil and natural gas from wells in shale and other unconventional formations that require extensive fracturing. We are vertically integrated:

 

   

We manufacture many of the components of our hydraulic fracturing units, including all of the hydraulic pumps we use in our operations, and assemble all of the hydraulic fracturing units used in our fleets.

 

   

We produce from our own mines and processing plants the majority of the raw sand and resin-coated sand we use as proppants.

 

   

We formulate and blend a portion of the chemicals we use in fracturing fluids.

 

   

We transport most of the raw sand and other products to job sites by rail and truck using our distribution network.

This vertical integration allows us to provide superior customer service, rapidly adapt to changing market conditions, maintain and control the quality of our equipment and products, and manage costs. We believe our vertical integration has been one of the key factors that has facilitated our rapid growth since 2004.

We believe we are the third largest hydraulic fracturing service company in the United States, based on total horsepower of our fleets. We believe we have one of the largest market shares of any hydraulic fracturing service provider in the Haynesville Shale, the Eagle Ford Shale and the Marcellus Shale, based on number of fleets. Currently, we have fleets operating out of 12 active district offices. During the first half of 2011, we opened a new district office in Elk City, Oklahoma to service customers in the Granite Wash formation and a new district office in Minot, North Dakota to service customers in the Bakken Shale. We have deployed two fleets to our Elk City district and three fleets to our Minot district. We anticipate deploying fleets in additional oil and natural gas producing areas in 2011, which may include the Utica Shale in Ohio.

Our historical financial information is presented on a “predecessor” basis for periods prior to May 6, 2011 and “successor” basis for periods beginning on or after May 6, 2011 to indicate the application of two bases of accounting.

Impacts of Acquisition Transaction

We recorded the Acquisition Transaction using the acquisition accounting method, under which the assets acquired and liabilities assumed were recorded at their estimated fair values as of May 6, 2011. These estimated fair values are subject to change and will be finalized as the information necessary to complete the analysis is obtained. The following table summarizes the provisional recording of assets acquired and liabilities assumed as of the acquisition date (in thousands):

 

Working capital

   $ 491,486   

Fixed assets

     1,321,913   

Intangible assets

     1,076,800   

Goodwill

     2,706,637   

Debt

     (618,543
  

 

 

 

Total

   $ 4,978,293   
  

 

 

 

 

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The significant impacts to results of operations for the successor period from May 6, 2011 through June 30, 2011 related to acquisition accounting are:

 

   

$52.7 million charge to costs of revenues—The carrying values of our sand and chemical inventories were marked up by $52.7 million to fair value as of May 6, 2011. Due to the high turnover rate for our inventories, the entire quantity and related costs as of the acquisition date were expensed as of June 30, 2011. There will be no further impact on our results of operations in subsequent periods.

 

   

$6.8 million charge to depreciation and depletion—The carrying values of our fixed assets (including sand reserves) were marked up by $512.0 million. This increased basis is being depreciated or depleted, as applicable, over the remaining useful lives or estimated remaining units of production.

 

   

$16.3 million charge to amortization—We recorded $978.2 million of definite-lived intangible assets, which are being amortized over their economic lives ranging from two to ten years.

As a result of the change of control, we also incurred $31.3 million of expenses related to certain employment agreements and ownership-based compensation.

Even though our operations did not change significantly due to the Acquisition Transaction, the expenses related to these changes in our basis of accounting affect certain expenses recognized in the successor period, thereby limiting the comparability of successor periods and predecessor period financial information.

Impact of Conversion

Prior to the consummation of our initial public offering of common stock pursuant to this prospectus, Frac Tech International, LLC will be converted into a Delaware corporation named FTS International, Inc. in a transaction which we refer to as our “Conversion.” As required under GAAP, upon completion of our Conversion, the impact of recognizing deferred tax assets and liabilities will be recorded as a charge to income in the fiscal quarter in which the Conversion occurs. As of June 30, 2011, the amount of the charge would have been $230 million.

Key Accomplishments

Our hydraulic fracturing business experienced rapid growth over the five-year period from 2004 through 2008. After a downturn in our industry in 2009, we resumed our rapid growth in 2010. The total horsepower of our hydraulic fracturing fleets increased from approximately 31,500 horsepower at the end of 2004 to approximately 1,312,750 horsepower as of June 30, 2011. Revenues for the six months ended June 30, 2011 were $1,096.4 million, compared to $451.9 million for the comparable period in 2010. Revenues for the year ended December 31, 2010 substantially exceeded revenues for the year ended December 31, 2008, which was our previous record year. Other highlights include:

 

   

We began fabricating and assembling our own hydraulic fracturing units in 2003, established in-house chemical blending operations in 2006, and began manufacturing our own hydraulic pumps using proprietary technology in 2006, which has allowed us to modify our equipment and fracturing fluids in response to customer requirements, using the knowledge and experience we gain by operating in harsh geological environments. We believe our technologically advanced fleets are among the newest, most reliable and highest performing in the industry with the capability of meeting the most demanding pressure and flow rate requirements in the field.

 

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We began mining and processing our own raw sand in 2007 in Missouri and in 2008 in Texas, and we acquired a resin-coating operation in Alabama in January 2009 and opened a resin-coating operation in Illinois in March 2011. Based on estimates by our internal geologist, we now have approximately 313 million tons of probable raw sand reserves. We believe the reserves we own will be sufficient to allow us to generally meet our sand requirements for at least the next 20 years, based on the currently anticipated requirements of our business and assuming adequate processing capacity. We also have agreements to obtain sand from land owned by third parties in Wisconsin and operate processing plants to serve that location. We plan to add production facilities to expand both our raw sand and our resin-coating operations during 2011.

 

   

In order to avoid delays based on product sourcing and logistical issues, we began developing our own sand distribution network in 2006. This network now includes 218 bulk hauling trailers which we own and approximately 2,050 rail cars which we lease and own. In addition to storage facilities at our district offices, we currently have seven separate sand distribution and storage facilities with railhead access.

As a result of these efforts, we believe our hydraulic fracturing operations are vertically integrated to a greater extent than our principal competitors. We are able to reduce both capital and operating costs, minimize delays based on equipment down time and ensure timely delivery of proppants or other products to the job site. This enables us to increase the utilization rates of our equipment and allows customers to avoid costs associated with delays in completing their wells. Our ability to complete jobs on a timely basis is a key component of our superior customer service and has allowed us to develop strong customer relationships with many of the leading E&P companies in the country.

Recent Trends Affecting Our Business

Our industry is cyclical. Volatility in oil and natural gas prices, and expected future prices, can cause significant changes in levels of capital expenditures and drilling activity by E&P companies and corresponding changes in demand for hydraulic fracturing services. Prior to mid-2008, we benefitted from increased spending by E&P companies spurred by high commodity prices for oil and natural gas. During the period from mid-2008 through mid-2009, commodity prices declined dramatically. This decline in commodity prices, together with the crisis in the credit markets, resulted in significant curtailments in drilling activity and capital expenditures by E&P companies, including spending for hydraulic fracturing services.

This downturn in our industry, which began in late 2008 and continued into the fourth quarter of 2009, caused a significant decrease in our revenues for the year ended December 31, 2009. We were in default with respect to certain covenants under our prior revolving credit facility as of December 31, 2009, which we resolved by entering into an amendment and forbearance agreement in January 2010 and an amended and restated facility in May 2010. This facility was terminated in November 2010. Notwithstanding these consequences of the downturn, we increased our market share in key markets and made a number of improvements in our operations during this period. We were able to accomplish this by reducing our operating costs while continuing to make capital expenditures as necessary to repair and maintain our existing fleet. These efforts positioned us to quickly redeploy our entire fleet when market conditions improved.

In addition to improving the efficiency of our operations, these actions allowed us to continue to provide excellent service to our customers and to establish new customer relationships during the downturn. As a result, we believe we increased our market share in most of our primary markets during 2009, which we believe enabled us to become a market share leader in the Haynesville Shale and in the Marcellus Shale. These actions also positioned us to respond quickly to customer requests for service when demand for hydraulic fracturing services increased beginning in late 2009 and early 2010.

Beginning in the fourth quarter of 2009, the hydraulic fracturing market improved dramatically. Since November 2009, all of our hydraulic fracturing units have been continuously deployed, other than during routine

 

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maintenance periods. This quick recovery enabled us to increase pricing as well as the utilization of our hydraulic fracturing units. The strengthening of demand in our market was mainly the consequence of the increase in natural gas drilling, although we have also experienced increased demand for our services in oil producing areas such as the Permian Basin and the Eagle Ford Shale. Our market share in the Eagle Ford Shale increased rapidly during 2010, and we believe we currently have one of the largest market shares of any hydraulic fracturing company in the Eagle Ford Shale, based on number of fleets. In the near future, we expect that our oil-directed activity will increase more rapidly than our gas-directed activity.

The following trends have increased the demand for our services, and we believe they will continue to impact our business in the near to intermediate term:

 

   

an increase in the development of unconventional resource plays, including natural gas- and oil-bearing shale;

 

   

an increase in hydraulic fracturing intensity in more demanding shale formations;

 

   

an increase in the oil-directed horizontal rig count;

 

   

tight supply of hydraulic fracturing equipment, proppant and other products; and

 

   

growing international interest in hydraulic fracturing.

Although our revenues have increased dramatically since the fourth quarter of 2009, our ability to continue such growth remains subject to factors beyond our control, such as prevailing economic conditions and market conditions in the E&P industry. Further, the rate at which our revenues are expected to grow in future periods will not be comparable to recent periods because our recent dramatic growth was preceded by a significant decrease that occurred during the industry downturn in late 2008 and much of 2009. The hydraulic fracturing market and the E&P industry are cyclical. Therefore, over the longer term, we anticipate that E&P activity, including horizontal drilling, and the corresponding demand for our services will experience periods of volatility. We cannot assure you that future downturns in our market will not have material adverse impacts on our business, financial condition or results of operations, notwithstanding the efforts we have taken, as noted above, to reduce the potential impact of such downturns on our revenues, pricing and utilization rates.

How We Generate Our Revenues

We derive substantially all of our revenues from the performance of hydraulic fracturing services for our customers. Historically, we have derived a majority of our revenues from engagements for one or a discrete series of hydraulic fracturing jobs, including a significant amount of recurring business from existing customers, rather than under long-term arrangements or contracts. In recent periods, we have derived an increasing portion of our revenues from arrangements and contracts pursuant to which we agree to dedicate one or more of our fleets to a customer’s operations, as described below. We generally are compensated based on the number of fracturing stages we complete for our customers. This, combined with pricing changes, allows our revenues to increase at rates in excess of drilling rig counts.

Many customers hire service companies through a competitive bidding process. We believe the principal factors in our industry on which hiring decisions are based are service quality, timing and availability of equipment and products, particularly proppants, performance history and price. Our strategy is not to compete primarily on the basis of price. Instead, we believe we have a competitive advantage based on the relationships we have developed with significant customers by consistently delivering exceptional service, our stable supply and ready availability of raw sand and other products, our reliable equipment, and our ability to operate at high pressures in harsh environments.

 

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We have entered into master service agreements with many of our clients. These agreements specify payment terms, audit rights and insurance requirements and allocate certain operational risks through indemnity and similar provisions. In general, our master service agreements allocate risks relating to surface activities associated with the hydraulic fracturing process, other than water disposal, to us and “down-hole” liabilities, and disposal of fracturing fluids used in the hydraulic fracturing process, to the customer. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well as waste water. The customers remove the water from the well using a controlled flow-back process, and we are not involved in that process or the disposal of the fluid. We supplement these agreements for each engagement with a bid proposal, subject to customer acceptance, containing such things as the estimated number of fracturing stages to be performed, pricing, quantities of products expected to be needed, and the number, horsepower and pressure ratings of the hydraulic fracturing fleets to be used.

Generally, we invoice our customers at the end of each fracturing stage during the engagement. Payment is typically required within 30 days after completion of the stage. The fees we charge are based on the time and materials we expend in providing our hydraulic fracturing services. Our invoices typically include:

 

   

an equipment charge determined by applying a base rate for the amount of time our hydraulic pumps are in operation, which rate varies based on the pressure, flow rate and horsepower required, and which is determined largely by the characteristics of the geological formation; and

 

   

product charges, determined by applying an agreed rate to the amount of proppant (by weight), chemicals (in gallons) and other products we consume in providing the hydraulic fracturing services.

In response to increased demand and the tight supply of hydraulic fracturing fleets in some of our key markets, we have agreed with a number of customers to allocate one or more of our fleets to their operations at agreed prices. These arrangements typically have 12- to 24-month terms and require customers to pay us an established rate per fracturing stage or a minimum amount per quarter. We have entered into such arrangements with 12 of our largest customers operating in the Haynesville, Eagle Ford, Marcellus and Bakken Shales and the Permian Basin. Currently, about one-third of our 33 fleets are dedicated to customers under these types of arrangements. These arrangements increase the predictability of our future revenues, improve our ability to deploy our fleets efficiently and enhance our customer relationships.

The Costs of Conducting Our Business

The principal expenses involved in conducting our hydraulic fracturing business are product costs and freight, the costs of manufacturing our hydraulic pumps and maintaining and repairing our hydraulic fracturing units, labor expenses and fuel costs. By being vertically integrated, we believe we are able to control costs to a greater extent than our competitors who do not produce their own raw sand and who do not have in-house manufacturing and maintenance facilities and operations.

Based on estimates by our internal geologist, we currently have approximately 313 million tons of raw sand reserves, which we have classified as probable reserves under the SEC’s disclosure rules. We also have two in-house resin-coating operations and expect to complete construction of a third facility in 2012. This stable supply of raw and resin-coated sand results in significant cost savings. Our raw sand and resin-coating sand operations supplied approximately 76.5% and 57.6%, respectively, of the raw sand and resin-coated sand we used as proppants in our hydraulic fracturing operations during the six months ended June 30, 2011. We also operate an extensive sand and chemical distribution network, which enables us to deliver proppants and chemicals to our hydraulic fracturing jobs quickly and on short notice. Our distribution network also results in savings on freight costs. The cost of sand, chemicals and freight represented approximately 35.2%, 28.0% and 34.1% of our revenues in 2009, 2010 and the first six months of 2011, respectively.

 

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We manufacture many of the components of and assemble all of the hydraulic fracturing units we use in our operations, and we also maintain and repair those units. We purchase from third-party vendors certain of the parts we use to manufacture our hydraulic pumps, as well as the other major components of our hydraulic fracturing units, including engines, transmissions, radiators and trailers, and other service equipment such as blenders and sand kings. We capitalize the costs of fabricating and assembling our hydraulic fracturing units and, historically, have depreciated those costs over ten years. Depreciation costs represented approximately 22.9%, 8.9% and 7.7% of our revenues in 2009, 2010 and the first six months of 2011, respectively. Our depreciation costs will increase significantly in the future due to the new basis of accounting recorded for our fixed assets as a result of the Acquisition Transaction. During 2010, we began operating in harsh geological environments to a greater extent than in prior periods and effective October 1, 2010, we began depreciating the cost of our hydraulic fracturing units over seven years, which we believe is a more appropriate useful life of our equipment given the effect of our increased operations in harsher shale environments. As a result of this change, we accelerated the depreciation of certain equipment that we had placed into service prior to that date, resulting in increased depreciation costs in the fourth quarter of the year, and there will be an incremental increase in the annual amount of depreciation attributable to our hydraulic fracturing units in future periods. Depreciation declined as a percentage of revenue in 2010 compared to 2009 as a result of the significant increase in revenue and the relatively fixed nature of depreciation. We estimate that our cost per hydraulic fracturing unit is approximately 30% less than the amount we would have to pay to a third-party manufacturer for a comparable unit.

Direct labor costs represented approximately 10.3%, 5.1% and 4.9% of our revenues in 2009, 2010 and the first six months of 2011, respectively. The decrease in direct labor costs, as a percentage of revenue, was due to the significant increase in our revenue.

We incur significant fuel costs in connection with the operation of our hydraulic fracturing units and the transportation of our equipment and products. Fuel costs represented approximately 7.6%, 5.3% and 5.3% of our revenues in 2009, 2010 and the first six months of 2011, respectively. Fuel usage increases in proportion to increases in the number, size and utilization of our fleets, and fuel prices, including delivery costs, are subject to significant fluctuations. The decrease in fuel costs, as a percentage of revenue, was due to the significant increase in our revenue, offset by increases in fuel costs.

Preventive and remedial repair and maintenance costs that do not involve the replacement of major components of our hydraulic fracturing units are expensed as incurred. These repair and maintenance costs represented approximately 10.9%, 9.5% and 9.5% of our revenues in 2009, 2010 and the first six months of 2011, respectively. These costs increase in proportion to increases in the number of hydraulic fracturing units we have in the field and in relation to increases in utilization of our equipment. During 2010, we began operating many of our fleets on multiple shifts per day. In addition, beginning October 1, 2010, we began expensing the cost of all fluid ends added as replacement parts to our hydraulic fracturing units. Prior to that date, fluid ends were capitalized and depreciated over time. As a result of these factors repair and maintenance costs increased during 2010 compared to the prior year. Repair and maintenance costs decreased slightly as a percentage of revenue, due primarily to the improvement in our pricing in 2010, partially offset by the change in accounting policy mentioned above. We perform substantially all repair and maintenance services on our hydraulic fracturing units through our service and manufacturing facilities and our maintenance and repair personnel who work out of our district offices. We also maintain a centralized parts inventory and distribution center in Cisco, Texas.

Prior to the Conversion, we have been treated as a partnership for federal income tax purposes and therefore have not directly paid federal or state income taxes on our income. The amounts we record as income tax for accounting purposes consist primarily of margin taxes paid to the State of Texas, which generally are determined on the basis of gross revenues from Texas sources, less certain deductions. Historically, our owners have been subject to income taxes on taxable income, if any, generated by us. After our Conversion, we will be treated as a corporation for tax purposes and will be required to pay federal and state income taxes. Our pro forma condensed consolidated statements of operations included elsewhere in this prospectus present pro forma

 

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tax expense to reflect the tax expense we would have incurred if we had been subject to tax as a corporation in the periods presented.

How We Evaluate Our Operations

A key financial and operating measurement that our management uses to analyze and monitor the operating performance of our business is Adjusted EBITDA, which consists of net income before interest, taxes, depreciation, amortization, gain or loss on sale of assets, ownership-based compensation and Acquisition Transaction costs, as further adjusted to add back amounts charged to income for goodwill impairment related to the discontinuance of the operations of a subsidiary in fiscal year 2008 and impairment of service equipment in fiscal year 2010. See “Prospectus Summary—Summary Consolidated Financial Information” and “Selected Consolidated Financial Data.” We also evaluate our performance using certain key operating data relating to the utilization of our hydraulic fracturing fleets and the level of activity in our business, based on, for example, the number of wells we service and the number of fracturing stages we perform. The following table shows certain operating data for the periods indicated:

 

          Predecessor          Successor     Combined  
    Year Ended December 31,     Six
Months
Ended

June 30,
2010
    January  1
through

May 5,
2011
         May  6
through

June 30,
2011
    Six
Months
Ended
June 30,
2011
 
    2006     2007     2008     2009     2010               

Operating Data—Unaudited:

                     

Number of wells fractured

    398        750        839        675        1,374        665        583            278        861   

Total fracturing stages

    *        *        *        4,786        9,916        4,253        5,086            2,506        7,592   

Average revenue per stage

    *        *        *      $  81,327      $    129,750      $    105,155      $ 142,951          $ 140,754      $ 142,226   

Horsepower (end of period)

    213,750        678,250        779,500         802,000        996,250        802,000        1,194,000            1,312,750        1,312,750   

Number of fleets deployed (end of period)

    11        16        19        20        23        20        27            31        31   

 

* Unavailable

We use the operating metrics shown above as a measure of performance, as is typical in the pressure pumping industry. We also use these metrics in forecasting our future business performance. Our management also evaluates and manages the performance of our business by comparing our current actual results against pressure pumping industry trends. Industry-specific trends and internal productivity analysis allow us to gauge our performance regarding margin expectations and operating efficiencies. Resources are then allocated throughout our company in order to achieve our expected hydraulic fracturing results.

 

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Results of Operations

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2011

The following table sets forth data from our consolidated statement of operations as a percentage of revenues for the periods shown. Historical results for the six months ended June 30, 2010 are compared and discussed in relation to the combined six month period ending June 30, 2011, which is comprised of the partial predecessor period from January 1, 2011 through May 5, 2011 and the partial successor period from May 6, 2011 through June 30, 2011.

 

    Predecessor          Successor     Combined  
    Six Months Ended
June 30, 2010
    Period from January 1 to
May 5, 2011
         Period from May 6 to
June 30, 2011
    Six Months Ended
June 30, 2011
 
    Amount     Percent of
Revenue
    Amount     Percent of
Revenue
         Amount     Percent of
Revenue
    Amount     Percent of
Revenue
 
   

(Unaudited)

         (Unaudited)  
   

(In thousands)

        

(In thousands)

 

Revenues

  $ 451,874        $ 729,365            $ 366,997        $ 1,096,362     

Costs of revenues, excluding depreciation, depletion and amortization

    245,482        54.3     365,480        50.1         245,763        67.0     611,243        55.8

Selling and administrative costs

    49,091        10.9     88,695        12.2         30,001        8.2     118,696        10.8

Depreciation, depletion and amortization

    52,959        11.7     52,553        7.2         49,134        13.4     101,687        9.3
 

 

 

     

 

 

         

 

 

     

 

 

   

Income from operations

    104,342        23.1     222,637        30.5         42,099        11.4     264,736        24.1

Other income (expense):

                   

Interest expense, net

    (11,529     2.6     (13,935     1.9         (22,829     6.2     (36,764     3.4

Other

    (66     0.0     (1,347     0.2         296        0.1     (1,051     0.1
 

 

 

     

 

 

         

 

 

     

 

 

   

Net other expenses

    (11,595     2.6     (15,282     2.1         (22,533     6.1     (37,815     3.4
 

 

 

     

 

 

         

 

 

     

 

 

   

Income before income taxes

    92,747        20.5     207,355        28.4         19,566        5.3     226,921        20.7

Provision for income taxes

    1,685        0.4     2,051        0.3         730        0.2     2,781        0.3
 

 

 

     

 

 

         

 

 

     

 

 

   

Net income

  $ 91,062        20.2   $ 205,304        28.1       $ 18,836        5.1   $ 224,140        20.4
 

 

 

     

 

 

         

 

 

     

 

 

   

Revenues. Revenues increased by $644.5 million, or 142.6%, from $451.9 million for the six months ended June 30, 2010 to $1,096.4 million for the six months ended June 30, 2011. This improvement was due to an increase in demand for our services resulting primarily from an increase in the horizontal rig count and drilling activity in our markets, as well as opening two districts to serve the Bakken Shale and Granite Wash formation in the first quarter of 2011. This increased demand resulted in an increase in the volume of activity. This increased activity, particularly in harsh shale environments in which we believe we have a competitive advantage, also allowed us to increase our prices. We estimate that over 70% of the increase in our revenues was due to increased activity.

Costs of Revenues. Costs of revenues increased by $365.8 million, or 149.0%, from $245.5 million for the six months ended June 30, 2010 to $611.2 million for the six months ended June 30, 2011. During the successor period from May 6 to June 30, 2011, we recognized a non-recurring cost of $52.7 million related to the impact of acquisition accounting on our inventory. The primary increase in costs of revenues was due to an overall increase in our operating activity, and the most significant increases were in the costs of products (such as sand and chemicals, which had increases in both volume and costs of materials), freight and fuel, primarily due to the larger volumes we used in our operations, and to a lesser extent direct labor costs, which increased with higher activity but were relatively consistent between periods on a per-fleet, per-shift basis. These increases were slightly offset by a non-recurring $5.7 million impairment of service equipment recorded in the first half of 2010. The net effect of the increase in the costs of revenues, combined with the significant increase in our revenues, was an increase in our costs as a percentage of revenues, from 54.3% of revenue for the six months ended June 30, 2010 to 55.8% of revenues for the six month period in 2011.

 

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Selling and Administrative Costs. Selling and administrative costs increased by $69.6 million, or 141.8%, from $49.1 million for the six months ended June 30, 2010 to $118.7 million for the six months ended June 30, 2011. This increase was due to an increase in costs associated with our increased activity level and the overall growth of our operations, $18.2 million of stock compensation expense, a $15.4 million increase in legal, professional and consulting fees, management bonuses of $13.1 million as a result of the change of control and $3.0 million of transaction costs related to the Acquisition Transaction.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased by $48.7 million, or 92.0%, from $53.0 million for the six months ended June 30, 2010 to $101.7 million for the six months ended June 30, 2011, primarily due to an increase in the number of hydraulic fracturing units we fabricated, assembled and used in our operations since June 30, 2010. In addition, we revised our estimate of the useful lives of our hydraulic fracturing units and certain other equipment from ten years to seven years effective October 1, 2010, which required us to accelerate the depreciation of such equipment placed into service prior to that date. We also recorded $23.1 million of additional depreciation, depletion and amortization during the successor period from May 6 to June 30, 2011 as a result of acquisition accounting. As a percentage of revenues, depreciation, depletion and amortization declined from 11.7% in the six months ended June 30, 2010 to 9.3% in the six months ended June 30, 2011 as a result of the significant increase in revenues and the relatively fixed nature of depreciation, offset by the impact of acquisition accounting.

Net Other Expenses. Net other expense increased by $26.2 million, or 226.1%, from $11.6 million for the six months ended June 30, 2010 to $37.8 million for the six months ended June 30, 2011. This increase was due to increased interest expense as a result of the issuance of $550 million principal amount of senior notes in November 2010 and our borrowing of $1.5 billion under our senior secured term loan in connection with the Acquisition Transaction on May 6, 2011.

Income Taxes. Income taxes increased by $1.1 million, or 65.0%, from $1.7 million for the six months ended June 30, 2010 to $2.8 million for the six months ended June 30, 2011. This increase was the result of higher margin taxes paid to the State of Texas, which are generally based on gross revenues, less certain deductions.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2010

The following table sets forth data from our consolidated statement of operations as a percentage of revenues for the periods shown:

 

     Year Ended December 31,  
     2009     2010  
     (In thousands)  

Revenues

   $ 389,230        $ 1,286,599     

Costs of revenues, excluding depreciation, depletion and amortization

     255,977        65.8     641,783        49.9

Selling and administrative costs

     68,386        17.6     136,299        10.6

Depreciation and amortization

     91,149        23.4     117,976        9.2
  

 

 

     

 

 

   

Income (loss) from operations

     (26,282     (6.8 )%      390,541        30.4

Other income (expense):

        

Interest expense, net

     (15,945     (4.1 )%      (19,476     (1.5 )% 

Other

     2,335        0.6     865        0.1
  

 

 

     

 

 

   

Net other expenses

     (13,610     (3.5 )%      (18,611     (1.4 )% 
  

 

 

     

 

 

   

Income (loss) before income taxes

     (39,892     (10.2 )%      371,930        28.9

Income Taxes

     347        0.1     3,254        0.3
  

 

 

     

 

 

   

Net income (loss)

   $ (40,239     (10.3 )%    $ 368,676        28.7
  

 

 

     

 

 

   

 

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Revenues. Revenues increased by $897.4 million, or 230.6%, from $389.2 million for the year ended December 31, 2009 to $1,286.6 million for the year ended December 31, 2010. This improvement was due to an increase in demand for our services resulting primarily from an increase in the horizontal rig count and drilling activity in our markets. The horizontal rig count increased from 145 to 172 in northwest Louisiana and east Texas, which includes the Haynesville and Cotton Valley Shales, and from 78 to 137 in the northeastern United States, which consists primarily of the Marcellus Shale, from December 31, 2009 to December 31, 2010. This increased demand resulted in an increase in the volume of activity. This increased activity, particularly in harsh shale environments in which we believe we have a competitive advantage, also allowed us to increase our prices. We estimate that approximately 40% of the increase in our revenues was due to increased prices and 60% to increased activity.

Costs of Revenues. Costs of revenues increased by $385.8 million, or 150.7%, from $256.0 million for the year ended December 31, 2009 to $641.8 million for the year ended December 31, 2010. The increase in costs of revenues was generally due to our overall increase in operating activity, and the most significant increases were in the costs of products (such as sand and chemicals, which had increases in both volume and costs of materials), freight (which had increases in both volume of freight and variable costs such as demurrage) and fuel. To a lesser extent, the costs associated with direct labor increased with higher activity but were relatively consistent between periods on a per-fleet, per-shift basis. The net effect of the increase in the costs of revenues combined with the significant increase in our revenues, which was driven in significant part by improved pricing, was a decrease in our costs as a percentage of revenue from 65.8% for the year ended December 31, 2009 to 49.9% of revenue for the year ended December 31, 2010.

Our operations in harsher geological environments such as the Haynesville and Marcellus Shales, which have represented an increasing portion of our operations in recent periods, have resulted in higher levels of stress on our hydraulic fracturing units, particularly the fluid ends, which is the part of the hydraulic pump through which the fracturing fluid is expelled under high pressure. As a result, we recorded an impairment of certain service equipment due to retirement earlier than its originally estimated useful life, which resulted in a $9.4 million cost being recognized in 2010.

Selling and Administrative Costs. Selling and administrative costs increased by $67.9 million, or 99.3%, from $68.4 million for the year ended December 31, 2009 to $136.3 million for the year ended December 31, 2010. This increase was due to an increase in costs associated with our increased activity level and the overall growth of our operations. We reduced our labor force during the year ended December 31, 2009 due to depressed economic and market conditions, and we rehired personnel as market conditions and demand for our services improved during the year ended December 31, 2010. Additionally, during the year ended December 31, 2010, we recorded compensation expense of $18.5 million relating to bonuses for previous owners and management. We did not pay any such bonuses in 2009. Selling and administrative costs decreased as a percentage of revenues for 2010 compared to 2009 primarily due to our revenues growing proportionately faster than our administrative expenses. Our selling and administrative costs were 17.6% of revenues for the year ended December 31, 2009 compared to 10.5% for the year ended December 31, 2010.

Depreciation and Amortization. Depreciation and amortization increased by $26.9 million, or 29.5%, from $91.1 million for the year ended December 31, 2009 to $118.0 million for the year ended December 31, 2010, primarily due to an increase in the number of hydraulic fracturing units we fabricated, assembled and used in our operations during 2010. In addition, we revised the estimate of the useful lives of our hydraulic fracturing units and certain other equipment from ten years to seven years effective October 1, 2010, which required us to accelerate the depreciation of such equipment placed into service prior to that date. As a percentage of revenues, depreciation and amortization declined from 23.4% in 2009 to 9.2% in 2010, as a result of the significant increase in revenues and the relatively fixed nature of depreciation.

Net Other Expenses. Other expense, net, increased by $5.0 million, or 36.8%, from $13.6 million for the year ended December 31, 2009 to $18.6 million for the year ended December 31, 2010. This increase was due

 

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primarily to increased interest expense as a result of higher rates that became effective under our prior revolving credit facility when it was extended beyond its original maturity pursuant to a forbearance agreement, prior to its refinancing.

Income Taxes. Income taxes increased by $2.9 million, or 837.8%, from $0.4 million for the year ended December 31, 2009 to $3.3 million for the year ended December 31, 2010. This increase was the result of higher margin taxes paid to the State of Texas, which are generally based on gross revenues, less certain deductions.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2009

The following table sets forth data from our consolidated statement of operations as a percentage of revenues for the periods shown:

 

     Year Ended December 31,  
     2008     2009  
     (In thousands)  

Revenues

   $ 573,543        $ 389,230     

Costs of revenues, excluding depreciation, depletion and amortization

     343,301        59.9     255,977        65.8

Selling and administrative costs

     81,940        14.3     68,386        17.6

Depreciation and amortization

     69,200        12.1     91,149        23.4

Goodwill impairment

     5,971        1.0     —          —     
  

 

 

     

 

 

   

Income (loss) from operations

     73,131        12.8     (26,282     (6.8 )% 

Other income (expense):

        

Interest expense, net

     (29,040     (5.1 )%      (15,945     (4.1 )% 

Other

     1,262        0.2     2,335        0.6
  

 

 

     

 

 

   

Net other expenses

     (27,778     (4.8 )%      (13,610     (3.5 )% 
  

 

 

     

 

 

   

Income (loss) before income taxes

     45,353        7.9     (39,892     (10.2 )% 

Income taxes

     1,994        0.3     347        *   
  

 

 

     

 

 

   

Net income (loss)

   $ 43,359        7.6   $ (40,239     (10.3 )% 
  

 

 

     

 

 

   

 

* Less than 0.1%

Revenues. Revenues decreased by $184.3 million, or 32.1%, from $573.5 million for the year ended December 31, 2008 to $389.2 million for the year ended December 31, 2009. This decrease was due to a significant reduction in demand for our services as customers decreased capital expenditures during the financial crisis and as a result of declines in commodity prices. We also experienced lower prices for the services that we did provide. We estimate that approximately 81.3% of the decrease in our revenues was due to the decline in prices and 18.7% due to decreased activity.

Costs of Revenues. Costs of revenues decreased by $87.3 million, or 25.4%, from $343.3 million for the year ended December 31, 2008 to $256.0 million for the year ended December 31, 2009, due to a significant decline in our activity, resulting from a dramatic decline in drilling activity in our markets. Costs of revenues increased from 59.9% of revenues for 2008 to 65.8% of revenue for 2009. The increase in the costs of revenues, as a percentage of revenues, was due primarily to the dramatic decline in activity and pricing resulting from unfavorable market conditions, to the fixed nature of many of our costs and to a lag in cost reduction initiatives implemented in early 2009. In addition, we transitioned more of our business to more challenging shale formations. Operating in the harsher shale formations, particularly the Haynesville Shale, required us to increase our use of more expensive proppants, such as resin-coated sand and ceramics. Finally, our repair and maintenance costs increased primarily because the prolonged downturn in the industry allowed us to perform routine repairs and maintenance procedures on our service equipment earlier than we might otherwise have performed these services.

 

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Selling and Administrative Costs. Selling and administrative costs decreased by $13.5 million, or 16.5%, from $81.9 million in 2008 to $68.4 million for the year ended December 31, 2009. This decrease was due to a reduction of our labor force and the implementation of other cost reduction initiatives in 2009.

Depreciation and Amortization. Depreciation and amortization increased by $21.9 million, or 31.7%, from $69.2 million for the year ended December 31, 2008 to $91.1 million for the year ended December 31, 2009, primarily due to depreciation related to a significant amount of equipment that was purchased or built in 2008. The net effect of the fixed nature of these assets and the depreciation cycle and the 32.1% decline in revenues was an increase in depreciation as a percentage of revenues from 12.1% in 2008 to 23.4% in 2009.

Goodwill Impairment. The $6.0 million goodwill impairment charge incurred in 2008 resulted from discontinued operations that resulted from the closing of a business we had purchased for priority rights to purchase equipment we sought from the manufacturer. The operation that we discontinued had insignificant assets as of the date we stopped these operations.

Net Other Expenses. Other expense, net, decreased by $14.2 million, or 51.1%, from $27.8 million for the year ended December 31, 2008 to $13.6 million for the year ended December 31, 2009, due primarily to a change in the fair value of our interest rate swap agreements from a liability of $10.7 million in 2008 to a liability of $5.7 million at December 31, 2009, and a reduction in our outstanding borrowings. Net changes in the value of interest rate swap agreements are recognized as income or expense for the period in which the changes occur. Other expense, which includes gain or loss on sale of assets, amortization expense and miscellaneous income, remained relatively unchanged year over year.

Income Taxes. Income taxes decreased by $1.6 million, or 82.6%, from $2.0 million for the year ended December 31, 2008 to $0.3 million for the year ended December 31, 2009. This decrease was due to a decrease in revenues from our Texas operations.

Liquidity and Capital Resources

Overview

Historically, we have met our liquidity needs principally from cash flows from operating activities, borrowings under bank credit agreements, equity investments by Chesapeake, equipment financings and borrowings by our subsidiaries. After completion of this offering, our primary source of cash will be cash flows generated from our operations. We also maintain a $100 million revolving credit facility and may pursue additional debt or equity financings in the public or private markets in the future. We believe that cash generated from operations and other financing arrangements will be sufficient to meet our working capital requirements, anticipated capital expenditures and scheduled debt payments for at least the next 12 months. Our ability to satisfy debt service obligations, to fund planned capital expenditures and to make any acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions, market conditions in the E&P industry and financial, business and other factors, many of which are beyond our control.

On August 5, 2011, we entered into a $100 million senior secured revolving credit facility in order to provide an additional source of liquidity for our working capital and other general corporate purposes. The revolving credit facility matures on August 5, 2016 and is secured by accounts receivable, inventory and proceeds thereof. We currently have not drawn any borrowings under this facility, so the entire amount is available for future borrowings. See “Description of Certain Indebtedness—Revolving Credit Facility.”

Our principal uses of cash are to fund our operations and our capital expenditures, primarily for expanding and maintaining our fleets and acquiring or expanding facilities and to service our outstanding debt. For a discussion of our capital expenditures, see “—Capital Expenditures.”

 

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On November 12, 2010, we completed a private offering of $550 million in principal amount of our 7.125% Senior Notes due 2018. We are not obligated to make any principal payments on our senior notes until they mature on November 15, 2018 on which date the entire principal amount is due. We pay interest on our senior notes semi-annually on May 15 and November 15. See “Description of Certain Indebtedness—7.125% Senior Notes due 2018.”

In connection with the Acquisition Transaction, we entered into a $1.5 billion senior secured term loan with a syndicate of financial institutions as lenders and Bank of America, N.A., as administrative agent. Borrowings under the senior secured term loan, which matures on May 6, 2016, were used to finance the Acquisition Transaction. Our senior secured term loan requires that we make quarterly interest payments and quarterly principal payments of $3.75 million and that we pay the balance on the maturity date, which is May 6, 2016. In addition, our senior secured term loan has a cash sweep provision that requires that each quarter we apply an amount of cash equal to the maximum amount we are permitted to distribute under the indenture governing our senior notes, less certain amounts. We must also prepay the senior secured term loan with all of the net proceeds from any sale of our equity interests (other than certain excluded issuances). See “Description of Certain Indebtedness—Senior Secured Term Loan.”

Since we have been treated as a partnership for income tax purposes prior to our Conversion, we have historically distributed cash to our owners for payment of income taxes on taxable income, if any, generated by us. Following our Conversion, we will be treated as a corporation and will be required to pay federal and state income taxes. This will result in an increase in cash we use to pay income taxes and a discontinuation of distributions to our owners to pay income taxes on taxable income that we generated. Therefore, this change will not result in a material change in our uses of cash.

Cash Flows

The table below summarizes our cash flows and is presented on a “predecessor” basis for periods prior to May 6, 2011 and “successor” basis for periods beginning on or after May 6, 2011 to indicate the application of two bases of accounting and on a combined basis for the six month period ended June 30, 2011.

 

    Year Ended December 31,     Predecessor          Successor     Combined  
    2008     2009     2010     Six Months
Ended
June 30,
2010
    Period from
January 1 to
May 5,
2011
         Period from
May 6 to
June 30,
2011
    Six Months
Ended
June 30,
2011
 
                      (Unaudited)     (Unaudited)          (Unaudited)     (Unaudited)  
    (In thousands)                   

Cash flow statement data:

                 

Cash flows from operating activities

  $ 61,790      $ 75,621      $ 405,847      $ 75,477      $ 205,979          $ 73,542      $ 279,521   

Cash flows from investing activities

    (152,707     (78,295     (262,499     (46,161     (167,770         (3,749,772     (3,917,542

Cash flows from financing activities

    89,977        28,290        122,394        (30,780     (98,440         3,661,659        3,563,219   

Opening cash

    1,363        423        26,039        26,039        291,781            231,550        291,781   

Closing cash

    423        26,039        291,781        24,575        231,550            216,979        216,979   

Net Cash Provided by Operating Activities

Cash flows from operations is a significant source of liquidity we use to fund capital expenditures, pay distributions and repay our debt. Changes in cash flows from operating activities are primarily impacted by the same factors that impact our net income, excluding non-cash items such as depreciation, depletion and amortization, ownership-based compensation and impairments of assets. See “—Results of Operations” above for discussion of changes in our results of operations.

Cash provided by operating activities was $75.5 million for the six months ended June 30, 2010 and $279.5 million for the six months ended June 30, 2011, reflecting a significant increase in our net income as

 

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adjusted for non-cash items. The changes in operating assets and liabilities did not vary significantly between these two time periods.

Cash provided by operating activities was $61.8 million, $75.6 million and $405.8 million for the years ended December 31, 2008, 2009 and 2010, respectively. These changes in cash flows primarily reflect the changes in net income adjusted for non-cash items. Cash flows from operations were also impacted by net increases in operating assets and liabilities in 2008 and 2010 versus a net decrease in operating assets and liabilities in 2009, when lower revenues caused us to manage our working capital to a smaller net balance.

Net Cash Used in Investing Activities

For the six months ended June 30, 2010, net cash used in investing activities was $46.2 million compared to $3,918.0 million in the six month period ended June 30, 2011. This large increase was due primarily to the $3,660 million acquisition of our predecessor as well as increased purchases of assets in order to support our significantly increased level of operations.

For the year ended December 31, 2009, net cash used in investing activities was $78.3 million compared to $262.5 million for the year ended December 31, 2010. Net cash used in investing activities for the year ended December 31, 2010 consisted primarily of purchases of property and equipment. Net cash used in investing activities for 2009 consisted primarily of purchases of property and equipment of $61.8 million and the purchase of a resin-coating sand business for $17.5 million.

Net Cash Provided by/(Used In) Financing Activities

Net cash used by financing activities was $30.8 million for the six months ended June 30, 2010 compared to net cash provided by financing activities of $3,563.2 million in the six month period ended June 30, 2011. Net cash provided by financing activities for the six months ended June 30, 2011 consisted primarily of contributions from members of $2,227.8 million related to the acquisition of our predecessor, proceeds of $1,456.9 million from borrowings under our senior secured term loan, offset by a decrease in long-term debt of $11.3 million, an increase in distributions to members of $107.5 million and a $100 million decrease in other contributions from members.

Net cash provided by financing activities was $28.3 million for the year ended December 31, 2009 compared to net cash provided by financing activities of $122.4 million for the year ended December 31, 2010. Net cash provided by financing activities for the year ended December 31, 2010 consisted primarily of proceeds of long-term debt, including approximately $537.0 million of net proceeds from our private offering of senior notes, which closed in November 2010 and a $100 million equity investment from Chesapeake. This was partially offset by cash used in financing activities consisting primarily of net repayments of $238.9 million under our prior revolving credit facility, $46.2 million used to repay other short- and long-term debt and $230.5 million in distributions to members.

Net cash provided by financing activities in 2009 consisted primarily of a $37.5 million equity investment by Chesapeake, partially offset by a net decrease in outstanding balances under our prior revolving credit facility of $12.4 million.

Capital Expenditures

Our policy is to invest in growth through capital expenditures, principally for the fabrication, assembly and maintenance of our hydraulic fracturing units, including the manufacture of the hydraulic pumps and the purchase of other component parts used in the fabrication and assembly of those units, such as engines, transmissions and radiators, facility acquisitions and the purchase of other equipment we use in our business, including blenders and sand kings. We may also consider acquiring other companies from time to time as opportunities arise.

 

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Capital expenditures amounted to $163.0 million, $61.8 million and $266.1 million in the years ended December 31, 2008, 2009 and 2010, respectively, and $279.1 million for the six months ended June 30, 2011.

A substantial portion of our 2010 capital expenditures was spent in connection with our production of 81 hydraulic fracturing units during the year. We have fabricated and assembled a significantly larger number of hydraulic fracturing units in 2011. In addition, we are increasing our raw sand and resin-coated sand production capacity and hydraulic pump manufacturing capacity during 2011.

In 2011, we expect our capital expenditures to be significantly higher than in 2010. This increase is due to our commitment to increase our horsepower deployed in the marketplace. As this decision was reviewed by our senior management, we took into consideration several factors, including a return-on-invested-capital analysis, the requests from our customers for additional dedicated fleets, the intended and perceived growth in horizontal rig counts and a general sense of timing in growing our business.

Contractual Commitments and Obligations

In the normal course of business, we enter into various contractual obligations that impact, or could impact, our liquidity. The following table summarizes our material obligations as of June 30, 2011, with projected cash payments in the years shown.

 

     Payments Due by Period  
     Total      July 1 –
December 31,

2011
     2012-2013      2014-2015      Thereafter  
    

(Unaudited)

 
    

(In thousands)

 

Long-term debt:

              

Senior secured term loan(1)

   $ 1,496,250       $ 7,500       $ 30,000       $ 30,000       $ 1,428,750   

7.125% Senior Notes(2)

     549,680         —           —           —           549,680   

Other long-term debt(3)

     20,630         5,575         11,659         2,628         768   

Interest(4)

     798,118         68,918         277,280         272,693         179,227   

Operating leases(5)

     87,593         13,446         46,642         16,481         11,024   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total(6)

   $ 2,952,271       $ 95,439       $ 365,581       $ 321,802       $ 2,169,449   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes amounts outstanding as of June 30, 2011. The total principal amount outstanding as of August 31, 2011 was $1,342,772. Our senior secured term loan has a cash sweep provision which requires that each quarter we apply an amount of cash equal to the maximum amount we are permitted to distribute under the indenture governing our senior notes, less certain amounts. Amounts reflected in the table above reflect scheduled quarterly payments of principal that are due, assume no payments are made in respect of the cash sweep provision and do not give effect to the use of proceeds of this offering, which we anticipate will include the prepayment of $         of the aggregate principal amount outstanding under our senior secured term loan. See “Use of Proceeds.”
(2) Assumes aggregate principal amount of $549.7 million of our senior notes will be outstanding until maturity.
(3) Consists of principal payments required under outstanding debt instruments.
(4) Consists of contractual interest payments on our senior secured term loan (assuming the interest rate effective as of June 30, 2011), senior notes and other indebtedness.
(5) Consists primarily of equipment leases. Amounts disclosed assume no exercise of options to renew or extend the leases.
(6) On August 5, 2011, we entered into a $100 million revolving credit facility which matures on August 5, 2016. We currently have no outstanding borrowings under that facility. We have no purchase obligations other than purchase orders or other contracts that we may cancel at any time without penalty, subject to minimum notice requirements of no more than 120 days. We have no material capital lease commitments or obligations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, other than normal operating leases included in the table above, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

 

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Critical Accounting Policies

Our consolidated financial statements are prepared in accordance with GAAP, which requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from these estimates. We have provided a description of all of our significant accounting policies in Note 2 to our unaudited interim consolidated financial statements included elsewhere in this prospectus. Listed below are the accounting policies we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved.

Fixed Assets

Fixed assets include land, sand reserves, facilities, equipment (which includes hydraulic fracturing units and other service equipment), vehicles and transportation equipment and construction in process. Fixed asset additions are recorded at cost, or fair value if acquired in the Acquisition Transaction, less accumulated depreciation, depletion and impairments, if any. Costs of hydraulic fracturing units we fabricate and assemble consists of materials, components, labor, overhead and capitalized borrowing costs. Land costs include the purchase price, plus zoning and other costs to prepare it for its intended purpose, and any improvements other than buildings.

We depreciate costs of fixed assets on a straight-line basis over the estimated useful lives of the assets. Historically, we depreciated the cost of our hydraulic fracturing units over an estimated useful life of ten years. Effective October 1, 2010, we revised our estimate of the useful lives of service equipment used in our hydraulic fracturing services to seven years, in part due to the increasing amount of operations we have conducted in harsher geological environments in recent periods. We do not separately depreciate the components we use in the assembly and fabrication of our hydraulic fracturing units. We depreciate other service equipment, such as trucks, mining equipment and manufacturing machinery, over estimated useful lives ranging from five to ten years. High-pressure iron, which is included in service equipment, is depreciated over a period of 30 months. We depreciate office equipment over estimated useful lives of three to seven years. Renewals and betterments are not considered in the determination of estimated useful lives. The cost of land and improvements, other than buildings, is not depreciated. Building improvements are depreciated over the lesser of the estimated useful life of the improvement or the remaining life of the building. Because of the cyclical nature of our business and other industry trends, which results in fluctuations in the use of our equipment and the environments in which we operate, the determination of useful lives of service equipment requires the exercise of significant judgment by our management.

Expenditures for renewals and betterments that extend the lives of our service equipment, which include the replacement of significant components of service equipment, are capitalized. Maintenance costs are generally expensed as incurred. Prior to January 1, 2010, we generally capitalized fluid ends added as replacement parts over a useful life of not less than 12 months. During 2010, we reassessed our policies regarding the useful lives of our service equipment. During that same period, we capitalized $6.7 million of fluid ends with a useful life of less than 12 months. Effective October 1, 2010, we have charged the cost of fluid ends added as replacement parts to costs of revenues upon installation.

Sand exploration costs, as well as drilling and other costs incurred for the purpose of converting mineral resources to probable reserves or identifying new mineral resources at development or production stage properties, are charged to expense as incurred. The costs incurred during the development stage (after probable reserves have been established and prior to commencement of commercial sand extraction), such as removal of overburden to gain access to probable reserves, which are not material, are charged to expense as incurred. As a result of the Acquisition Transaction, we recognized a sand reserve asset of $371.7 million, which primarily relates to our extensive raw sand reserves in Voca, Texas, Katemcy, Texas and Perryville, Missouri. We recognize depletion expense of our sand reserves using unit-of-production method based on estimated recoverable probable reserves. Also included in sand reserves is an amount associated with the value beyond proven and probable reserves

 

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(“VBPP”). Our VBPP is attributable to undeveloped land consisting of potential sand reserves which we believe could be brought into production with the establishment or modification of required permits and should market conditions and technical assessments warrant. Carrying amounts assigned to VBPP are not charged to expense until the VBPP becomes associated with additional probable reserves and the reserves are produced or the VBPP is determined to be impaired. Additions to probable reserves for properties with VBPP will carry with them the value assigned to VBPP at the date acquired, less any impairment amounts.

We review the carrying value of property, plant and equipment for impairment whenever events or circumstances indicate that the carrying value of an asset may not be recoverable from estimated future cash flows expected to result from its use and eventual disposition. In cases where undiscounted expected future cash flows are less than the carrying value, an impairment loss equal to the amount by which the carrying value exceeds the fair value of assets is recognized. When making this assessment, the following factors are considered: current operating results, trends and prospects, as well as the effects of obsolescence, demand, competition and other economic factors.

Impairment of Goodwill

We accounted for the Acquisition Transaction using the acquisition method of accounting and allocated the purchase price to the tangible and intangible assets acquired and liabilities assumed based upon their estimated fair values on the date of the Acquisition Transaction. We recorded the excess of the purchase price over tangible assets, identifiable intangible assets and assumed liabilities in the amount of $2.7 billion as goodwill, which is substantially higher than the goodwill in our predecessor period financial statements.

Goodwill is not amortized but is tested for impairment annually as of December 31, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. The goodwill impairment test compares the fair value of a reporting unit, generally based on discounted future cash flows, with its carrying amount including goodwill. If the carrying amount of a reporting unit exceeds its fair value, a non-cash impairment charge is measured as the difference between the implied fair value of the reporting unit’s goodwill and the carrying amount of goodwill.

Impairment of Long-Lived Assets Other Than Goodwill

As a result of the Acquisition Transaction, we recorded $1.1 billion of identified intangible assets based on their estimated fair values as of the date of the Acquisition Transaction, of which $1.0 billion are definite-lived assets and are being amortized over their estimated economic lives. We review the carrying values of our long-lived assets, including fixed assets and intangible assets excluding goodwill, for impairment whenever events or circumstances indicate that the carrying value of an asset or group of assets may not be recoverable from estimated future cash flows expected to result from its use and eventual disposition. In cases where undiscounted expected future cash flows are less than the carrying value, we recognize an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets. When making this assessment, the following factors are considered: current operating results, trends and prospects, as well as the effects of obsolescence, demand, competition, and other economic factors.

The determination of future cash flows as well as the estimated fair values of long-lived assets involves significant estimates on the part of management. If there is a material change in economic conditions or other circumstances influencing the estimate of future cash flows or fair value, we could be required to recognize non-cash impairment charges in the future.

Income Taxes

Prior to our Conversion, we have been treated as a partnership for federal income tax purposes and therefore have not directly paid income taxes on our income nor have we benefitted from losses. Instead, our

 

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income and other tax attributes have been passed through to our owners for federal and, where applicable, state income tax purposes. The provision for income taxes in our historical financial statements is for the Texas margin tax and other partnership taxes, which are deemed to be income taxes for financial accounting purposes.

As required by the uncertain tax position guidance under GAAP, we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. We have not recognized any financial statement benefits or obligations related to uncertain tax positions.

Following our Conversion we will be treated as a corporation for tax purposes and will be required to pay federal and state income taxes. Our pro forma condensed consolidated statements of operations included elsewhere in this prospectus present pro forma tax expense to reflect the tax expense we would have incurred if we had been subject to tax as a corporation in the historical periods presented. We have computed pro forma tax expense using a 35% corporate-level federal tax rate. This rate is adjusted for permanent differences between the income reported for book and tax purposes. The effective tax rate includes a corporate level state income tax rate with consideration to apportioned income for each state of operation.

Recent Accounting Pronouncements

In December 2010, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update requiring that the second step of the goodwill impairment test (i.e., measurement and recognition of an impairment loss) be performed if a reporting unit has a carrying value equal to or less than zero and qualitative factors indicate that it is more likely than not that a goodwill impairment exists. The provisions of this update are effective for annual reporting periods beginning after December 15, 2010. We do not expect the effects of adoption to have a significant impact on the results of our goodwill impairment testing.

In December 2010, the FASB issued an accounting standards update relating to disclosure of supplementary pro forma information for business combinations. This guidance provides clarification on disclosure requirements and amends current guidance to require entities to disclose pro forma revenue and earnings of the combined entity as though the acquisition date for all business combinations that occurred during the current year had been as of the beginning of the comparable prior annual reporting period. Qualitative disclosures describing the nature and amount of any material, nonrecurring pro forma adjustments directly attributable to the business combinations included in the reported pro forma revenue and earnings are also required. This guidance is effective for business combinations with acquisition dates on or after the beginning of the first annual reporting period beginning on or after December 15, 2010, with early adoption permitted. This pronouncement affects only disclosures and did not impact our financial condition and results of operations.

In May 2011, the FASB issued an accounting standards update related to fair value measurements and disclosures to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with United States GAAP and International Financial Reporting Standards. This guidance includes amendments that clarify the intent about the application of existing fair value measurement requirements, while other amendments change a principle or requirement for measuring fair value or for disclosing information about fair value measurements. Specifically, the guidance requires additional disclosures for fair value measurements that are based on significant unobservable inputs. The updated guidance is to be applied prospectively and is effective for our interim and annual periods beginning January 1, 2012. The adoption of this guidance is not expected to have a material impact on our financial condition, results of operations or cash flows.

 

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In June 2011, the FASB issued an accounting standards update relating to the presentation of other comprehensive income. The accounting update eliminates the option to present components of other comprehensive income as part of the statement of stockholders’ equity. Instead, companies must report comprehensive income in either a single continuous statement of comprehensive income (which would contain the current income statement presentation followed by the components of other comprehensive income and a total amount for comprehensive income), or in two separate but consecutive statements. This guidance is effective for our fiscal year beginning January 1, 2012. This guidance may impact our presentation of other comprehensive income, but will not impact our financial condition, results of operations or cash flows.

Quantitative and Qualitative Disclosures about Market Risk

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate under our revolving credit facility. We have borrowings outstanding under, and may in the future borrow under, fixed rate and variable rate debt instruments that give rise to interest rate risk. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument but may affect our future earnings and cash flows.

Our primary exposure to interest rate risk results from outstanding borrowings under our senior secured term loan, which we entered into on May 6, 2011. Outstanding borrowings under our senior secured term loan bear interest at a rate per annum equal to LIBOR, plus an applicable margin based on our leverage. Our vulnerability to changes in LIBOR could result in material changes to our interest expense, as a one percentage point increase or decrease in interest rate payable on senior secured term loan would have impacted our interest expense by approximately $2.3 million for the period from May 6 to June 30, 2011.

 

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BUSINESS

Our Company

We are a leading independent provider of oil and natural gas well stimulation services with expertise in high-pressure hydraulic fracturing. We currently operate 33 hydraulic fracturing fleets with 1,393,500 horsepower in the aggregate. We have leading positions in the primary U.S. shale plays and are actively exploring international expansion into areas where the geology is similar to the U.S. unconventional basins in which we currently operate. We are vertically integrated, unlike the majority of our competitors. We manufacture many of the components of our hydraulic fracturing units, mine, process and transport a majority of our proppant requirements and formulate and blend a portion of the chemicals we use in our operations.

We believe the vertical integration of our operations reduces our operating costs, increases our asset utilization, improves our supply chain flexibility and responsiveness and ultimately enhances our financial performance and ability to provide high-quality customer service. We manufacture durable equipment based on proprietary designs that we believe provides superior performance in the most demanding applications while extending the useful life of our equipment. Unlike manufacturers without service operations, we are able to incorporate the knowledge acquired in our hydraulic fracturing operations to improve our equipment designs. We also have significant maintenance and repair capabilities, and we manufacture replacement parts to support our operations and enhance our asset utilization. Our raw sand reserves and processing operations provide us with ready access to the two principal proppants we use in our operations, raw sand and resin-coated sand, which can often be in short supply in the required specifications. Additionally, we formulate and blend a portion of the chemical compounds we use in our operations, which allows us to provide tailored solutions to our customers. Our chemical offerings include some of the most environmentally friendly products in the industry, most of which produce no harmful by-products and require no auxiliary chemicals. Our technical staff of engineers, chemists, technicians and a geologist support our operations by optimizing the design and delivery of our equipment, products and services and by continually seeking to improve the quality, durability and effectiveness of the solutions we provide to our customers.

Our revenues have grown from $214.4 million in 2006 to $1,286.6 million in 2010, a compound annual growth rate of 56.5%. For the six months ended June 30, 2011 our revenues were $1,096.4 million and our Adjusted EBITDA was $453.5 million, representing increases of 143% and 178%, respectively, compared to the six months ended June 30, 2010. We are benefitting from a number of positive industry developments, including a dramatic increase in the amount and efficiency of horizontal drilling activity, an increase in the number of hydraulic fracturing stages per well and an increase in drilling activity in oil- and liquids-rich shale formations. These trends have led to increased asset utilization in our industry and a tight supply of fracturing fleets, proppants and other fracturing-related services and products. We also believe there is growing international interest in horizontal drilling and fracturing methods.

 

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Our fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of a high-pressure hydraulic pump, a diesel engine, a transmission and various hoses, valves, tanks and other supporting equipment that are typically mounted on a flat-bed trailer. The group of hydraulic fracturing units, other equipment and vehicles necessary to perform a typical fracturing job is referred to as a “fleet” and the personnel assigned to each fleet are commonly referred to as a “crew.” In areas where we operate on a 24-hour-per-day basis, we typically staff two crews per fleet. The following table summarizes the amount of horsepower and the number of hydraulic fracturing fleets that we operate as of August 31, 2011:

 

Formation

  

Location

   Total
Horsepower
     Fleets  

Haynesville Shale

   Louisiana, East Texas      396,750         7   

Eagle Ford Shale

   South Texas      281,000         6   

Marcellus Shale

   Pennsylvania, West Virginia      242,750         6   

Permian Basin

   West Texas, New Mexico      201,550         7   

Bakken Shale

   North Dakota, Montana      106,750         3   

Granite Wash

   Oklahoma, North Texas      97,500         2   

Barnett Shale

  

North Texas

     45,000         1   

Rockies

   Utah      22,200         1   
     

 

 

    

 

 

 

Total

        1,393,500         33   

E&P companies operating in the United States use our services primarily to enhance their recovery rates from wells drilled in shale and other unconventional reservoirs. Our operations are focused primarily in unconventional oil and natural gas formations in the Haynesville Shale, the Eagle Ford Shale, the Marcellus Shale, the Permian Basin and the Bakken Shale. We believe we have one of the largest market shares of any hydraulic fracturing service provider in the Haynesville Shale, the Eagle Ford Shale and the Marcellus Shale, based on number of fleets. In recent months, we have obtained an increasing number of engagements in connection with oil-directed drilling, particularly in the Eagle Ford Shale and the Permian Basin. In 2011, we began serving customers in the Bakken Shale and the Granite Wash formation. Our engagements in these areas primarily relate to horizontal drilling for oil and other hydrocarbon liquids. We expect to continue to deploy new fleets in additional regions with significant oil- and liquids-directed drilling activity through the end of 2011. The customers we currently serve are primarily large E&P companies such as Chesapeake Energy Corporation, Anadarko Petroleum Corporation, El Paso Corporation, Marathon Oil Corporation, Petrohawk Energy (owned by BHP Billiton Ltd.), Range Resources Corporation and XTO Energy (owned by Exxon Mobil Corporation).

We currently manufacture many of the components of our hydraulic fracturing units, including all of the hydraulic pumps, and we assemble all of the hydraulic fracturing units in our fleets. At full capacity, we are capable of producing up to 30 hydraulic fracturing units, with an aggregate of approximately 75,000 horsepower, per month. To increase the durability, reliability and utilization of our hydraulic fracturing units, we manufacture a proprietary hydraulic pump consisting of two key assemblies, a power end and a fluid end. Although the power end of our pumps generally lasts several years, the fluid end, which is the part of the pump through which the fracturing fluid is expelled under high pressure, is a shorter-lasting consumable, often lasting less than one year. We currently have the capacity to manufacture up to 30 power ends and 150 fluid ends per month to equip new hydraulic fracturing units and to replace the fluid ends on our existing units. Because we build and service our own fluid ends, they are designed to provide high performance at low cost and to have greater longevity than those manufactured by third parties.

We own and operate sand mines, related processing facilities, resin-coating facilities and a distribution network that provide us with a reliable and low cost supply of raw and resin-coated sand. Our raw sand operations supplied approximately 65.1% and 76.5% of the raw sand we used as proppants in our hydraulic fracturing operations during 2010 and the six months ended June 30, 2011, respectively. Our resin-coating operations supplied approximately 49.3% and 57.6% of the resin-coated sand we used as proppants during 2010 and the six months ended June 30, 2011, respectively. We have processing plants at our two sand mines in Texas

 

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and Missouri and also obtain and process sand from agricultural sources in Wisconsin. We are currently capable of processing approximately 1.9 million tons per year of raw sand, which is the most common type of proppant we use in our hydraulic fracturing operations. As of June 30, 2011, we had an estimated 313 million tons of probable sand reserves. See “—Sand Production and Distribution—Sand Reserves.” Our resin-coating facilities currently have the capacity to produce approximately 650,000 tons of resin-coated sand annually. Resin-coated sand is raw sand that has been processed and coated with resin and has a greater resistance to crushing forces compared to raw sand. We use resin-coated sand as a proppant in the more geologically challenging formations that require fracturing at higher pressures. We intend to expand our raw sand and resin-coated sand production capacity over the next 12 months. See “—Sand Production and Distribution—Sand Production.” In addition to our mines and processing plants, we have eight operating sand distribution facilities in Texas, Louisiana and Pennsylvania, 218 bulk hauling trailers for highway transportation and approximately 2,050 rail cars, which enable us to deliver proppants to our fracturing jobs quickly and on short notice.

In addition, we formulate and blend a portion of the chemical compounds that we use in fracturing fluids at our chemical manufacturing facility and research and development laboratories.

Industry Overview

The pressure pumping industry provides hydraulic fracturing and other well stimulation services to E&P companies. Hydraulic 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 props open the cracks created by the hydraulic fracturing process in the underground formation. Proppants generally consist of sand, resin-coated sand or ceramic particles. The total size of the hydraulic fracturing market, based on revenue, was estimated to be approximately $10.5 billion in 2009, $18.0 billion in 2010 and is estimated to be $22.5 billion in 2011 based on data from a 2011 report by Spears & Associates.

When drilling a horizontal well, the E&P company directs drillers to drill vertically into the formation, and steer the drill string to create a horizontal section of the wellbore inside the target formation, which is referred to as a “lateral.” This lateral is divided into “stages” which are isolated zones that focus the high-pressure fluid and proppant from the hydraulic fracturing fleet into distinct portions of the wellbore and surrounding formation. Customers typically compensate hydraulic fracturing service providers based on the number of stages fractured.

The main factors influencing demand for hydraulic fracturing services in North America are the level of horizontal drilling activity by E&P companies and the fracturing requirements, including the number of fracturing stages and the volume of fluids, chemicals and proppant pumped per stage, in the respective resource plays. The hydraulic fracturing market is cyclical and is largely influenced by drilling and completion expenditures by our customers. Since late 2009, there has been a significant increase in both horizontal drilling activity and related hydraulic fracturing requirements, which has increased the demand for our services.

A recent phenomenon that has increased the demand for fracturing services has been the development of unconventional oil- and natural gas-rich fields in the United States. Conventional production seeks to recover oil or natural gas that is trapped in a reservoir below the surface, and requires only a conventional vertical well to recover the oil or natural gas. Conversely, unconventional oil and natural gas production requires hydraulic fracturing and other well stimulation techniques to recover oil or natural gas that is trapped in the source rock and typically involves horizontal drilling. The estimated natural gas supply in the United States increased by 35% between 2006 and 2008, primarily due to the development of unconventional resource plays, and shale gas resources have grown from 5% of total production in 2006 to 20% in 2009.

Two technologies—hydraulic fracturing and horizontal drilling—are critical to recovering oil and natural gas from unconventional formations. Increased demand for unconventional production has resulted in more horizontal drilling, which increases demand for our hydraulic fracturing services. Additionally, horizontal drilling techniques are increasingly being applied in conventional basins. Horizontal wells have also become

 

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longer and more complex, resulting in (i) an increase in the number of fracturing stages per well, (ii) more intensive fracturing (as measured by relative horsepower used per day per job) and (iii) an increase in the amount of proppant used per well and per stage.

The following chart illustrates the recent trend in the number of rigs with horizontal and vertical drilling activity in the United States, depicting an increasing share of rigs with horizontal drilling.

LOGO

A trend that has further increased the demand for hydraulic fracturing services is the increase in the number of oil-related horizontal rigs as compared with the number of natural gas-related rigs.

The following chart illustrates the recent trends depicting the increase in the oil-related horizontal rig count as compared to the natural gas-related horizontal rig count.

LOGO

 

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Industry Trends Impacting Our Business

Industry revenues are generally impacted by the following trends and have recently been growing significantly in excess of rig count.

Increase in Fracturing Stages Resulting from Horizontal Drilling Activity

Advances in drilling and completion technologies including horizontal drilling and hydraulic fracturing have made the development of many unconventional resources, such as oil and natural gas shale formations, economically attractive. This has led to a dramatic increase in the development of oil- and natural gas-producing shale formations, or “plays,” in the United States. According to Baker Hughes, the U.S. horizontal rig count has risen from 337 at the beginning of 2007 to 1,136 at September 2, 2011, increasing from 20% to 58% of total rig count. As E&P companies have become more experienced at developing shale plays, the time required to drill wells has decreased, thus increasing the number of wells drilled per year and hence the number of fracturing stages demanded for a given rig count. At the same time, the length of well laterals is increasing, and fracturing stages are being performed at closer intervals. As a result, the number of fracturing stages is growing at a faster rate than the horizontal rig count, leading to a significant increase in the demand for hydraulic fracturing services.

Increased Service Intensity and Activity in More Demanding Shale Reservoirs

Many of the new shales that have been discovered, such as the Haynesville and Eagle Ford Shales, are high-pressure reservoirs that require more durable equipment, a greater amount of horsepower and more technically sophisticated forms of proppant, such as resin-coated sand and ceramic proppants. The additional horizontal drilling activity, coupled with the demanding characteristics of unconventional reservoirs, has put increasing demands on hydraulic fracturing equipment. We focus on the most demanding reservoirs where per stage revenues are higher and where we believe we have a competitive advantage due to the high performance and durability of our equipment.

Increased Drilling in Oil- and Liquids-Rich Formations

There is increasing drilling activity in oil- and liquids-rich formations in the United States, such as the Eagle Ford, Bakken, Niobrara and Utica Shales and various plays in Oklahoma, including the Granite Wash formation. Additionally, hydraulic fracturing services are increasingly being deployed in traditionally oil-focused basins like the Permian Basin. Although the E&P industry is cyclical and oil prices have historically been volatile, we believe that many of the oil- and liquids-rich plays are economically attractive at oil prices substantially below the current prevailing oil price. We believe this should provide continued and growing opportunities for our services in the near term.

Tight Supply of Hydraulic Fracturing Fleets, Proppants and Other Products

Due to increased drilling in unconventional formations, hydraulic fracturing fleets, proppants, replacement and repair parts and other products became increasingly scarce since 2010, as demand increased for hydraulic fracturing services. Moreover, individual fracturing stages have become more intensive, requiring more fluids, chemicals and proppant per stage. Based on current market conditions, we expect this trend to continue throughout 2011 and into 2012. We are well positioned to take advantage of the market scarcity due to our vertical integration strategy because we supply our own hydraulic pumps and the majority of our proppant requirements, and we manufacture many of the components of and repair our hydraulic fracturing units in-house.

 

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Growing International Interest in Hydraulic Fracturing

There is growing international interest in the development of unconventional resources such as oil and natural gas shales. This interest has resulted in a number of recently completed joint ventures between major U.S. and international E&P companies related to shale plays in the United States. We believe that these joint ventures, which generally require the international partner to commit to significant future capital expenditures, will provide additional demand for hydraulic fracturing services in the coming years. Additionally, we believe such joint ventures will continue to stimulate the development of other oil and natural gas shales outside the United States. The technological advances seen in the United States over the last five years can be applied to unconventional basins internationally, allowing foreign countries to reach the level of drilling and fracturing efficiency currently being achieved in the United States. We believe rapid development of cost-effective oil and natural gas reserves has the potential to provide an attractive source of energy for rapidly developing emerging economies.

Competitive Strengths

We believe that we have the following competitive strengths:

Vertically Integrated Business

Our vertical integration provides us with a number of competitive advantages. For example, the amount of time required to fabricate and assemble a hydraulic fracturing unit is significantly reduced as a result of our in-house capabilities. Moreover, once our units are deployed, they are able to continue to operate with minimal delays for our customers, because our ability to quickly provide replacement fluid ends and other consumables reduces our maintenance turnaround time. Similarly, our raw sand and resin-coating operations provide a reliable source of proppant for our operations. Our sand distribution centers and our transportation infrastructure reduce the logistical challenges inherent in our business by allowing us to transport and deliver proppant and equipment quickly to our fracturing jobs on short notice.

Because we produce most of the key equipment and products necessary for our operations, we are able to provide prompt service while controlling costs. We estimate that our manufacturing costs per fracturing unit are approximately 30% less than we would pay to purchase a similar fracturing unit from outside suppliers and that our manufacturing cost per fluid end is approximately 50% less than we would pay to purchase a similar fluid end from outside suppliers. Similarly, we are able to produce proppants such as raw sand and resin-coated sand and to blend chemicals at lower cost than we would typically pay for such products from outside suppliers. As a result, our vertically integrated business improves our margins, reduces our maintenance capital expenditures and improves our equipment utilization. These factors enable us to provide superior service at competitive prices, thereby increasing customer satisfaction, strengthening our existing customer relationships and helping us to expand our customer base.

High-Quality Fleet

We maintain high-quality fleets of hydraulic fracturing units and related equipment. Our 33 fleets have 1,393,500 horsepower in the aggregate, are strategically located throughout our principal markets and have an average age of less than four years. We believe our fleets are among the most reliable and highest performing in the industry with the capability of meeting the most demanding pressure and flow rate requirements in the field. Our equipment’s durability minimizes delays and reduces maintenance costs. Moreover, we maintain our high-quality fleets through our manufacturing and repair facilities and our maintenance and repair personnel who work out of our district offices, which allow us to service, repair and rebuild our equipment quickly and efficiently without incurring excessive costs. These factors increase utilization of our fleets and enhance customer satisfaction because of reduced down time and delays.

 

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Advanced Equipment and Products

Our engineering team has enabled us to create what we believe to be one of the most technologically advanced and durable fleets of hydraulic pumps in the industry. We believe that, within the industry, we manufacture and deploy one of the most durable fluid ends, which is the part of the hydraulic pump that requires replacement most frequently. We also have chemical blending and research and development facilities where our technical staff designs and improves upon the composition of the chemicals we add to hydraulic fracturing fluids based on specific customer needs and geological factors. For example, we have filed a U.S. patent application for a new additive that uses nano particles to enhance the recovery of hydrocarbons from significantly depleted hydrocarbon formations. In addition, our technical staff has developed innovative techniques for completing and stimulating wells in unconventional formations that have helped establish us as a market leader in our industry.

Highly Active, High-Quality Customer Base

We have long-standing relationships with many of the leading oil and natural gas producers operating in the United States. Our largest customers include Chesapeake, El Paso Corporation, Petrohawk Energy (owned by BHP Billiton Ltd.), Range Resources Corporation and XTO Energy (owned by Exxon Mobil Corporation). Since 2002, we have broadened our customer base as a result of our technical expertise, high-quality hydraulic fracturing fleets and reputation for quality and customer service. We currently have more than 170 customers. Our strong customer relationships provide us with significant revenue visibility in the near to intermediate term and facilitate our ability to opportunistically expand our business to provide services to our customers in multiple areas in which they have operations. In addition, we have dedicated a larger portion of our fleets to some of our largest customers.

Leading Market Share in Key Unconventional Resource Plays

As a result of our focus on superior service and strong customer relationships, we believe we have one of the largest market shares of any hydraulic fracturing company in the Haynesville Shale, the Eagle Ford Shale and the Marcellus Shale, based on number of fleets. In addition to our current leading positions, we have recently begun serving customers in the Bakken Shale and the Granite Wash formation, and we have plans to expand into other prolific unconventional resource plays where significant demand exists for high-quality hydraulic fracturing services. Our leading market positions in the most demanding shale plays create economies of scale that allow us to more efficiently deploy our crews and to increase our productivity, efficiency and performance.

Incentivized Work Force

The managers of our hydraulic fracturing crews are eligible to receive incentive pay per fracturing stage based on customer and senior management satisfaction and subject to satisfying quality and safety standards. In addition, all of our field employees are eligible for incentive pay based on customer and management satisfaction and satisfying safety standards. We believe these incentive programs enable us to achieve higher utilization, attract the most competent work force and motivate our employees to continually maintain quality and safety. The discretionary incentive pay available under these programs has the potential to significantly supplement the earnings of our fleet managers and field employees.

Experienced Management Team

We have an experienced management team that includes Marcus C. Rowland, our chief executive officer, James Coy Randle, Jr., our president and chief operating officer, Charles Veazey, our senior vice president of operations, Robert Pike, our senior vice president of sales, Chris Cummins, our senior vice president of proppants and Brad Holms, our senior vice president—global business development and technology, who collectively have over 190 years of oilfield business experience. The remainder of our management team is comprised of seasoned operating, marketing, financial and administrative executives, many of whom have prior

 

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experience at prominent oilfield service companies such as BJ Services Company, Halliburton Corporation and Schlumberger Limited. Our management team’s extensive experience in and knowledge of the oilfield services industry strengthens our ability to compete and manage our business through industry cycles.

Strategy

We intend to build upon our competitive strengths to grow our business and increase our revenues and operating income. Our strategy to achieve these goals consists of (1) expanding our geographic footprint in the United States and internationally, (2) increasing our proppant production and distribution and our equipment manufacturing capabilities, (3) continuing to enhance our contract terms, (4) further increasing asset utilization and (5) evaluating opportunities for complementary services.

Expand Geographic Footprint in the United States and Internationally

We will continue to expand our operations to regions containing unconventional formations that are likely to require multi-stage high-pressure hydraulic fracturing efforts. For example, we deployed six fleets with approximately 281,000 aggregate horsepower to serve customers in the Eagle Ford Shale since June 30, 2010. In the first half of 2011, we deployed five new fleets with approximately 177,500 aggregate horsepower to serve customers in the Granite Wash formation and the Bakken Shale.

We are exploring international expansion into areas where the geology is similar to the U.S. unconventional basins in which we currently operate. By applying our technologies to these new areas we believe we can help producers achieve levels of drilling and completion efficiencies comparable to those in the United States in less time than it took in the U.S. market. Based on a report from the U.S. Department of Energy, international shale gas recoverable reserves are 6.7 times those in the United States. We are actively working to establish relationships with local reserve holders and to provide them stimulation services at the appropriate time in their development plans. We currently believe the most attractive international markets for our services are China, the Middle East and South America.

Increase Proppant Production and Distribution and Equipment Manufacturing Capabilities

We intend to increase our raw sand production capacity by expanding our existing processing plants in Texas and opening an additional sand processing plant in Texas. In addition, we plan to continue to increase our resin-coated sand production capacity over the next few years, and are constructing a new resin-coating plant in Texas that we expect to complete later in 2011. We are enlarging our distribution network to support the expansion of our sand operations. We also intend to increase our hydraulic pump manufacturing capacity and enhance our manufacturing capabilities by expanding our existing plants and adding new plants.

Continue to Enhance Contract Terms

We intend to continue to enhance our contract terms with our customers to increase the predictability of our future revenues, improve our ability to deploy fleets efficiently and enhance our customer relationships. In response to increased demand and tight supply of fracturing fleets in some of our key markets, we have agreed with some of our customers to dedicate one or more of our fleets to their operations at agreed prices. These arrangements typically have 12- to 24-month terms and require customers to pay us an established rate per fracturing stage or a minimum amount per quarter. We have entered into such arrangements with 12 of our largest customers operating in the Haynesville, Eagle Ford, Marcellus and Bakken Shales and the Permian Basin. Currently, about one-third of our fleets are dedicated to customers under these types of arrangements.

 

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Further Increase Asset Utilization

We will continue to focus on increasing asset utilization, particularly in the most demanding reservoirs. We are generally compensated based on the number of fracturing stages we complete. Each of our fleets historically completed one fracturing stage per day, but our fleets now typically complete multiple stages per day, usually on the same well. We have the ability to operate our fleets on a 24-hour-per-day, seven-day-per-week basis with two crews rotating to increase asset efficiency. Increases in the number of stages per well allow us to increase revenues for a given crew by reducing travel and mobilization time between jobs. In addition, we seek to increase asset utilization by scheduling fracturing jobs that are geographically close to one another.

Evaluate Opportunities for Complementary Services

We will continue to seek opportunities to further grow our business by adding complementary service offerings. We expect that new services that we may add will be focused primarily on improving the quality, reliability and deliverability of our existing service offerings.

Hydraulic Fracturing Operations

We provide high-pressure hydraulic fracturing (or frac) services to E&P companies. Hydraulic fracturing services are performed to enhance the production of oil and natural gas from formations having low permeability such that the natural flow is restricted. We have significant expertise in the hydraulic fracturing of multi-stage horizontal oil- and natural gas-rich wells in shale and other unconventional geological formations. In prior periods, most of our engagements were for natural gas wells. In recent months, we have obtained an increasing number of engagements in connection with oil wells, particularly in the Permian Basin and the Eagle Ford Shale. In the first quarter of 2011, we began serving customers in the Bakken Shale and in the Granite Wash formation. Our engagements in these areas primarily relate to horizontal drilling for oil and other hydrocarbon liquids. We expect to deploy new fleets in additional regions with significant oil- and liquids-directed drilling activity in 2011.

The hydraulic fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, in our case primarily sand or resin-coated sand, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. To a lesser extent, we also use ceramic materials, which we obtain from third party suppliers, as proppants. The fracturing fluid is designed to “break,” or lose viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well as waste water. The customers remove the water from the well using a controlled flow-back process, and we are not involved in that process or in the disposal of the fluid.

We own and operate fleets of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of a high-pressure hydraulic pump, a diesel engine, a transmission and various hoses, valves, tanks and other supporting equipment that are typically mounted on a flat-bed trailer. The group of hydraulic fracturing units, other equipment and vehicles necessary to perform a typical hydraulic fracturing job is referred to as a “fleet” and the personnel assigned to each fleet are commonly referred to as a “crew.” For information about the equipment that is typically included in a fleet, see “—Properties and Equipment—Equipment” below. In areas where we operate on a 24-hour-per-day basis, we typically staff two crews per fleet. We fabricate and assemble all of our hydraulic fracturing units and manufacture all of our hydraulic pumps in order to enhance the performance and durability of our equipment and meet our customers’ needs. See “—Our Company” above.

An important element of hydraulic fracturing services is determining the proper fracturing fluid, proppants and injection program to maximize results. Our field engineering personnel provide technical evaluation and job design recommendations for customers as an integral element of our hydraulic fracturing

 

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service. Technological developments in the industry over the past several years have focused on proppant density control, liquid gel concentrate capabilities, computer design and monitoring of jobs and cleanup properties for fracturing fluids.

During fiscal years 2008, 2009 and 2010 and the first six months of 2011, our capital expenditures were $163.0 million, $61.8 million, $266.1 million and $279.1 million, respectively. This investment demonstrates our commitment to growing our business and the significant capital required to be a major participant in the industry, particularly in shale and other unconventional formations that place intense mechanical demands on hydraulic fracturing equipment.

Our operations are focused in areas of the United States in which there are significant onshore shale formations in which E&P companies are actively developing and producing oil and natural gas. The shale areas in which we are currently most active are the Haynesville Shale, the Eagle Ford Shale and the Marcellus Shale. These geologically demanding shale formations are typically hydraulically fractured in order to be productive. We also have significant operations in the Permian Basin and have recently begun operating in the Bakken Shale and the Granite Wash formations.

Haynesville Shale. We believe we currently have one of the largest market shares of any hydraulic fracturing company in the Haynesville Shale in northwest Louisiana and east Texas, based on number of fleets. During 2010 and in the first six months of 2011, our operations in the Haynesville Shale generated the largest percentage of our revenues of any region. The Haynesville Shale reservoir is defined by a shale formation located approximately 1,500 feet below the Cotton Valley formation at depths ranging from approximately 10,500 feet to 13,000 feet. The Haynesville Shale, which is as much as 300 feet thick and composed of an organic rich black shale, has become one of the most active natural gas reservoirs in the United States. As of June 30, 2011, there were approximately 139 horizontal drilling rigs being operated in the Haynesville Shale, and a single well may be completed in as many as 25 stages, or horizontal zones, each of which requires a separate hydraulic fracturing job. We currently have seven fleets operating in the Haynesville Shale, consisting of 174 hydraulic fracturing units with approximately 396,750 aggregate horsepower.

Eagle Ford Shale. We began operations in the Eagle Ford Shale in south Texas in the third quarter of 2010, and we believe we currently have one of the largest market shares of any hydraulic fracturing company in the Eagle Ford Shale, based on number of fleets. The Eagle Ford Shale, which is as much as 200 feet thick, ranges in depth between approximately 4,000 and 14,000 feet. This shale, which does not have significant natural fractures, is considered the “source rock” for the Austin Chalk and Edwards formations above it. As of June 30, 2011, there were approximately 110 horizontal drilling rigs being operated in the Eagle Ford Shale. Our first significant engagement in the Eagle Ford Shale was in August 2010. We currently have six fleets operating in this area, consisting of 119 hydraulic fracturing units with approximately 281,000 aggregate horsepower.

Marcellus Shale. We also believe we currently have one of the largest market shares of any hydraulic fracturing company in the Marcellus Shale in Pennsylvania and West Virginia, based on number of fleets. The Marcellus Shale ranges in thickness from approximately 150 to 200 feet at depths between approximately 5,000 and 8,000 feet. As of June 30, 2011, there were approximately 158 horizontal drilling rigs being operated in the Marcellus Shale. We have been operating in the Marcellus Shale since 2007. We currently have six fleets operating in this area, consisting of 104 hydraulic fracturing units with approximately 242,750 aggregate horsepower.

Permian Basin. We began our operations in the Permian Basin in west Texas and southeast New Mexico in 2007. The Permian Basin contains shale formations of various thicknesses and depths. As of June 30, 2011, there were approximately 86 horizontal drilling rigs being operated in west Texas and New Mexico, where the Permian Basin is located. We currently have seven fleets operating in this area, consisting of 81 hydraulic fracturing units with approximately 201,550 aggregate horsepower.

 

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Bakken Shale. We began operations out of a new district office in Minot, North Dakota serving customers in the Bakken Shale in the first quarter of 2011. The Bakken Shale, an oil-rich formation in North Dakota and Montana, ranges in thickness from approximately 100 to 200 feet at depths between approximately 8,000 and 10,000 feet. As of June 30, 2011, there were approximately 182 horizontal drilling rigs being operated in the Bakken Shale. We currently have three fleets operating in this area, consisting of 34 hydraulic fracturing units with approximately 106,750 aggregate horsepower.

Granite Wash. We began operations out of a new district office in Elk City, Oklahoma serving customers in the Granite Wash formation in the first quarter of 2011. The Granite Wash, an oil and natural gas formation in Oklahoma and north Texas, ranges in thickness from approximately 1,500 to 3,500 feet at depths between approximately 11,000 and 13,000 feet. As of June 30, 2011, there were approximately 72 horizontal drilling rigs being operated in the Granite Wash formation. We currently have two fleets operating in this area, consisting of 39 hydraulic fracturing units with approximately 97,500 aggregate horsepower.

Barnett Shale. We restarted our operations out of our district office in Aledo, Texas serving customers in the Barnett Shale in the third quarter of 2011. The Barnett Shale, a natural gas formation in the Fort Woth basin of north Texas, ranges in thickness from approximately 30 to 1,000 feet at depths between approximately 2,500 and 7,000 feet. As of June 30, 2011, there were approximately 61 horizontal drilling rigs being operated in the Barnett Shale. We currently have one fleet operating in this area, consisting of 20 hydraulic fracturing units with approximately 45,000 aggregate horsepower.

Rockies. We currently have one fleet providing fracturing services in the Uinta Basin out of our Vernal, Utah district office consisting of eight hydraulic fracturing units and several smaller pumping systems with approximately 22,200 aggregate horsepower.

Sand Production and Distribution

Sand Production

The proppants we use most frequently are raw sand and resin-coated sand. A reliable source of raw sand and the ability to deliver it to job sites quickly and efficiently are crucial to the success of our business. This is particularly significant during periods in which there are shortages of sand, such as during late 2008. As activity in our industry increased in the fourth quarter of 2009 and throughout 2010, demand for and prices of raw sand and resin-coated sand increased significantly. The industry has experienced shortages in raw sand in certain markets during 2011, and we expect such shortages to continue. We have sought to mitigate any shortages by acquiring land containing extensive deposits of raw sand, and by operating our own mining and processing facilities and resin-coating operations, which provides us with a stable source of proppants to reduce our exposure to potential shortages.

Raw sand is the least expensive widely-used proppant in the industry. Raw sand that is compliant with American Petroleum Institute standards is available primarily in only two areas of the country in large quantities, namely, the northern midwest (Ottawa sand) and central Texas (Brady sand). All the processed raw sand we ship from our processing facilities meets American Petroleum Institute standards. See “—Sand Reserves.” We began our mining operations in Perryville, Missouri in 2007 and in Voca, Texas in 2008. We believe the reserves of Brady sand and Ottawa sand that we own will be sufficient to allow us generally to meet our sand requirements for at least the next 20 years, based on the currently anticipated requirements of our business and assuming adequate processing capacity. See “—Sand Reserves.” In addition to the reserves we own, we are party to agreements under which we have rights to obtain Ottawa sand excavated by landowners engaged in agricultural operations in Wisconsin.

We own processing plants at our Texas and Missouri mining locations and at two locations in Wisconsin. We are currently capable of processing approximately 1.9 million tons of raw sand per year. We

 

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obtain some of the raw sand we use as proppants from third-party suppliers. Our raw sand operations supplied approximately 65.1% and 76.5% of the raw sand we used as proppants in our hydraulic fracturing operations during the year ended December 31, 2010 and the six months ended June 30, 2011, respectively. The approximate aggregate amounts of processed raw sand we shipped from our four active processing plants were 500,000 tons in 2009, 1.1 million tons in 2010 and 793,000 tons in the first six months of 2011.

In addition to raw sand, we use resin-coated sand as proppants in the more geologically challenging formations that require hydraulic fracturing at higher pressures. Resin-coated sand is raw sand that has been processed and coated with resin. We acquired a resin-coating operation in Birmingham, Alabama effective January 1, 2009 and opened a resin-coating operation in Illinois in March 2011, in order to provide a stable supply of resin-coated sand for our operations. We are constructing a new resin-coating plant in Voca, Texas that we anticipate will be completed in 2012, subject to obtaining the necessary permits. During 2009, 2010 and the first six months of 2011, we shipped approximately 92,000 tons, 239,000 tons and 123,000 tons, respectively, of resin-coated sand from our resin-coating facilities. We used all of the resin-coated sand we processed during 2010 and the six months ended June 30, 2011 as proppants in our hydraulic fracturing operations. We obtain some of the resin-coated sand we use as proppants from third-party suppliers. Our resin-coating sand operations supplied approximately 49.3% and 57.6% of the resin-coated sand we used as proppants in our hydraulic fracturing operations during the year ended December 31, 2010 and the six months ended June 30, 2011, respectively.

We produce resin-coated sand at our Birmingham facility primarily using raw sand from our own mines. We currently operate four production lines at this facility with a combined annual production capacity of approximately 385,000 tons of resin-coated sand. We opened a resin-coating operation in Cutler, Illinois in March 2011, consisting of two production lines that will provide an estimated annual production capacity of approximately 260,000 tons of resin-coated sand.

Sand Distribution

We operate an extensive sand distribution network. Our sand distribution facilities include a central distribution facility that we own in Cleburne, Texas and seven operating satellite facilities in Texas, Louisiana and Pennsylvania that we own or lease. We own 218 bulk hauling trailers used for highway transportation of sand and we lease or own approximately 2,050 rail cars. Additional details about our sand distribution facilities are set forth in the table below.

 

Facility Location

   Silo Storage
Capacity
(in tons)
     Number of
Silos
 

Owned

     

Cleburne, Texas

     1,600         8   

Longview, Texas

     3,000         12   

Monahans, Texas

     2,100         12   

Pleasanton, Texas

     7,200         10   

Leased

     

Hughes Springs, Texas(1)

     —           —     

Glenwood, Pennsylvania(1)

     —           —     

Minot, North Dakota(1)(2)

     —           —     

Rook, Pennsylvania

     1,400         8   

Shreveport, Louisiana

     4,200         24   

 

(1) Represent transload facilities at which product is stored in rail cars.
(2) Under construction and not yet operational.

 

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In addition to our silo storage capacity, each of our rail cars has a capacity of approximately 100 tons, giving us approximately 205,000 tons of additional capacity. At any time, a significant number of our rail cars may be assigned to a specific facility, which provides additional storage capacity at the facility on an as-needed basis.

Through our sand distribution centers and transportation infrastructure, we are better able to service our customers’ short-notice needs and provide solutions to the logistical challenges presented by the large volume of sand required for fracturing jobs. We use our trailers and rail cars to move this sand quickly and efficiently from our strategically located sand distribution centers to our customers’ well sites, enabling us to minimize work stoppages and delays often created in our industry by logistical issues related to proppant sourcing.

There are significant barriers to entry into the raw sand and resin-coated sand businesses, including the costs of acquiring significant reserves of Brady sand or Ottawa sand, the costs of building processing facilities and establishing a distribution network and the permit processes, which can be complex and protracted. We believe these barriers to entry, together with our extensive reserves and the scope of our existing and planned production facilities and distribution network, give us a significant competitive advantage.

Sand Reserves

We own extensive reserves of raw sand near Voca, Texas, Katemcy, Texas and Perryville, Missouri. Reserves are estimated by our internal geologist based upon drilling and testing data sufficient to elevate reserves to probable (or “indicated”) status, within the meaning of the SEC’s disclosure rules. All of our sand reserves, before extraction, are in the form of sandstone in open pits, and may be located under varying thicknesses of overburden consisting of material such as topsoil, clay, silt or rock such as shale or limestone. Our estimates of probable reserves are of Brady sand and Ottawa sand of suitable quality for economic extraction, recognizing reasonable economic and operating constraints as to excavation, maximum depth of overburden, and permit or zoning restrictions. Substantially all the sand we extract from our mines meets American Petroleum Institute standards for use as proppants in hydraulic fracturing, which include standards for the sphericity, roundness, acid solubility and crush-resistance of the sand particles.

Our reserve estimates are of quantities of sandstone in place before extraction. The extraction process primarily involves stripping of overburden, drilling and blasting to reduce the sandstone to a manageable size, excavating the raw sand and loading it for transport to our processing facilities. On average, approximately 20% to 35%, by weight, of the sandstone we extract from our mine near Voca, Texas and approximately 90% to 95%, by weight, of the sandstone we extract from our mine near Perryville, Missouri yields processed raw sand of mesh sizes that we currently use in our hydraulic fracturing operations.

We are conducting active mining operations at our Voca, Texas and Perryville, Missouri locations and have applied for permits necessary to begin mining operations at our Katemcy, Texas location. See “—Sand Production.” The following table contains information about our estimated, in-place probable sand reserves on land that we own at these locations based on a report as of April 30, 2011 prepared by our internal geologist.

 

Sand Mine Location

   Acres Owned      Status    Internally
Estimated
Probable Reserves
 

Voca, Texas

     1,233       Active      232 million tons   

Perryville, Missouri

     250       Active      34 million tons   

Katemcy, Texas

     200       Permit Pending      47 million tons   
  

 

 

       

 

 

 

Total

     1,683            313 million tons   
  

 

 

       

 

 

 

During 2009, 2010 and the first six months of 2011, we extracted an estimated 1,291,000 tons, 3,300,000 tons and 1,962,000 tons of raw sand, respectively, in the aggregate, from our two active sand mines.

 

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We own approximately 331 acres of sand reserves in Ottawa, Illinois, which are not reflected in the table above. We do not currently have permits at this location to mine sand and no efforts are currently underway to obtain any such permits.

In late 2010 and the first half of 2011, we acquired an additional 1,360 acres of land adjacent to our existing reserves in Voca, Texas. We also own 100 acres of land in Missouri near our existing reserves in Perryville, Missouri. The drilling and testing necessary to elevate the sand reserves on this additional Voca and Perryville acreage, which is not reflected in the table above, to a reportable status has not been performed.

In addition to the reserves we own, we are party to agreements under which we obtain Ottawa sand excavated by landowners engaged in agricultural operations in Wisconsin. We process raw sand obtained under these agreements at our processing plants in Oakdale and Readfield, Wisconsin.

All of our mine facilities are accessible by public roadways and are served by public and rural cooperative power sources. The approximate aggregate cost at which we acquired the land and the equipment currently located at our mines consisted primarily of approximately $32.9 million for our assets near Voca, Texas and approximately $32.1 million for our assets near Perryville, Missouri.

Our internal geologist is Victor L. Kastner, Vice President of Operations of the subsidiary through which we conduct our raw sand mining and processing operations. Mr. Kastner received his B.S. in Geology from Fort Lewis College in 1978 and has more than 30 years of experience as a professional geologist. He received his certification as a Registered Professional Geologist from the State of Wyoming.

Manufacturing Operations

We fabricate and assemble all the hydraulic fracturing units we use in our operations at our manufacturing facilities in Cisco, Texas. At this facility, we also manufacture many of the components used in our hydraulic fracturing units, including fuel tanks, structural brackets, hoses and mufflers. At our facility in Fort Worth, Texas, we manufacture all the high-pressure hydraulic pumps used in our hydraulic fracturing units. At our Aledo, Texas facility, we have recently begun manufacturing manifolds, which are a significant component of our hydraulic fracturing units, and certain of the other service equipment we use in our operations, including blenders and hydration units. In the future, we may also manufacture these items at our Cisco facility. We anticipate that we will consolidate our Forth Worth and Aledo manufacturing operations into a newly-acquired facility located in Fort Worth in 2012.

Our in-house manufacturing operations enable us to increase the durability, reliability and utilization of our hydraulic fracturing units, which allows us to perform in geologically demanding formations that many of our competitors are unable to fracture efficiently. Our manufacturing operations also provide significant benefits to our customers by reducing down time due to equipment failure. We can also modify our proprietary equipment designs quickly in response to customer requirements, using the knowledge and experience we gain by operating in harsh geological environments. We believe our technologically advanced fleets are among the newest, most reliable and highest performing in the industry with the capability of meeting the most demanding pressure and flow rate requirements in the field. We also perform maintenance and repair services on our equipment at our manufacturing facilities and at our district facilities, which allows us to service and repair our equipment quickly and efficiently without incurring excessive costs. This further increases utilization of our fleets and enhances customer satisfaction because of reduced down time and delays. For these reasons, we believe our in-house manufacturing operations give us a significant competitive advantage.

Operating at full capacity, our manufacturing facility in Cisco, Texas is capable of producing up to 30 hydraulic fracturing units, with approximately 75,000 aggregate horsepower, per month. In 2008, we produced 100 hydraulic fracturing units at this facility. Due to weakness in the E&P market, we curtailed

 

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manufacturing activities during 2009 by producing 16 hydraulic fracturing units in 2009. In response to increased activity in our industry, we produced 81 hydraulic fracturing units during 2010 and 104 hydraulic fracturing units during the first six months of 2011. We anticipate that we will produce 236 hydraulic fracturing units in the full year 2011.

To increase the durability, reliability and utilization of our hydraulic fracturing units, we manufacture a proprietary hydraulic pump consisting of two key assemblies, a power end and a fluid end. Although the power end of our pumps generally lasts several years, the fluid end, which is the part of the pump through which the fracturing fluid is expelled under high pressure, is a shorter-lasting consumable, typically lasting less than one year. We currently have the capacity to manufacture up to 30 power ends and 150 fluid ends per month to equip new hydraulic fracturing units and to replace the fluid ends on our existing fleets. We intend to increase our high-pressure pump manufacturing capacity through expansion of existing plants and the addition of new plants.

We estimate that our manufacturing cost per fracturing unit is approximately 30% less than we would pay to purchase a similar fracturing unit from outside suppliers and that our manufacturing cost-per-fluid end is approximately 50% less than we would pay to purchase a similar fluid end from outside suppliers.

We purchase from third-party vendors certain of the parts we use to manufacture our hydraulic pumps, as well as certain other major components of our hydraulic fracturing units, including engines, transmissions, radiators and trailers, and some of our other service equipment such as blenders and sand kings.

Chemical Blending Operations

We formulate and blend a portion of the chemical compounds we use in fracturing fluids in our chemical manufacturing facility and research and development laboratories in Chickasha, Oklahoma. By employing a staff of chemists and other technical personnel at these facilities, we are able to improve the effectiveness of fracturing fluids using proven laboratory testing methods and information from our operating personnel about the effectiveness of fracturing fluids in the field. We believe our chemical blending operations give us the ability to produce some of the most technologically advanced fracturing fluids in the industry. For example, through our research and development efforts, we have developed an additive for fracturing fluids that uses nano particles to enhance recovery of hydrocarbons from significantly depleted reservoirs. We have filed a U.S. patent application for the process by which this additive enhances recovery of oil and natural gas. By continually improving the chemicals used in our operations, in many cases with our own proprietary formulas, we are able to control the quality of fracturing fluids.

By blending the chemicals at our own facilities, we are also able to reduce costs. We believe our in-house chemical development and blending operations give us a competitive advantage over our competitors who purchase all of their chemicals from third-party suppliers.

Properties and Equipment

In addition to our sand reserves, our sand distribution network and related properties and assets, our principal properties include our sand processing plants, mining facilities and equipment, district office facilities, manufacturing facilities and equipment and parts distribution centers, as well as the hydraulic fracturing units and other equipment and vehicles operating out of these facilities. We believe our facilities and equipment are generally in good condition and suitable for the purposes for which they are used.

Sand Processing Plants

We currently operate four raw sand processing plants in Voca, Texas, Perryville, Missouri, and Oakdale and Readfield, Wisconsin. We plan to expand our raw sand processing plant in Voca, Texas and open a new raw sand processing plant in Katemcy, Texas. We expect to complete these facilities in 2012, subject to completing

 

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the permitting process. See “—Sand Production and Distribution—Sand Production.” Our raw sand processing plants include facilities for crushing sandstone and for screening, scrubbing, dewatering and drying raw sand, as well as storage silos and conveyors.

We currently operate two resin-coating plants: one in Birmingham, Alabama, with four production lines, and the other in Cutler, Illinois, which began operating in March 2011, with two production lines. We are constructing a third resin-coating plant in Voca, Texas, with two production lines, which we expect to complete in 2011, subject to completing the permitting process. See “—Sand Production and Distribution—Sand Production.” Our resin-coating plants include facilities for heating raw sand, mixing the heated sand with resin and scalping and cooling the resin-coated sand, as well as storage silos and conveyors.

For information about the production capacity and annual production of our raw sand processing plants and resin-coating facilities, see “—Sand Production and Distribution—Sand Production.”

Sand Mining Equipment

The equipment at our sand mining facilities includes excavating equipment used to remove overburden, where necessary, and to extract sandstone from our mines. Our active mines are open pit mines. We employ mining contractors for drilling and blasting required to reduce the sandstone to manageable size. We typically use our own equipment for stripping, loading and hauling sandstone to our primary crushing facilities. Our equipment includes articulated trucks, rigid-frame trucks, track-mounted excavators, front end loaders and miscellaneous other equipment. Because we commenced our mining operations in Missouri in 2007 and in Texas in 2008, most of our equipment is relatively new.

District Offices

We currently have 12 district offices out of which we conduct hydraulic fracturing services. We continue to use the Aledo facility as our transportation and logistics headquarters, as a training center and as an equipment repair, maintenance and electronics installation facility. We have also recently begun manufacturing or assembling certain components of our hydraulic fracturing units and other service equipment at the Aledo facility. See “—Manufacturing Operations.” The following table provides certain information about our district office locations. Except as indicated, we own the land and facilities at each of these locations. In the aggregate, we own 296 acres and lease 18 acres of land on which our district facilities are located.

 

            Facilities  

District Office

 

Primary Area of Service

 

Geological
Formation

  Size (Sq. Ft.)
(approx.)
    Acres
(approx.)
 

Aledo, Texas

  Fort Worth Basin   Barnett Shale     88,550        25   

Artesia, New Mexico

  Southeast New Mexico   Permian Basin     20,500        16   

Brownsville, Washington County, Pennsylvania(1)

 

 

Pennsylvania, West Virginia and New York

  Marcellus Shale     31,000        18   

Bryan, Texas

  Southeast Texas   Freestone Trend     17,500        18   

Elk City, Oklahoma

  Oklahoma   Granite Wash     11,480        21   

Longview, Texas

  East Texas and West Louisiana   Haynesville Shale     36,000        14   

Minot, North Dakota

  North Dakota and Montana   Bakken Shale     21,600        2   

Odessa, Texas

 

Southeast New Mexico

and West Texas

  Permian Basin     47,820        30   

Pleasanton, Texas

  South Texas   Eagle Ford Shale     24,960        113   

Shreveport, Louisiana

  Ark-La-Tex area   Haynesville Shale     45,680        40   

Vernal, Utah

  Rocky Mountain area in Utah   Uinta Basin     20,800        10   

Williamsport, Pennsylvania

  Pennsylvania   Marcellus Shale     19,000        7   

 

(1) Leased facility.

 

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We own an additional 28-acre facility in Conway, Arkansas (from which we served the Fayetteville Shale) that we used as a district office until late 2008. We can reopen this facility if we determine it is needed for operations in the region in the future.

We own approximately 410 additional acres of undeveloped land, primarily in Colorado, Oklahoma, New Mexico, Texas and Utah, of which we are holding approximately 77 acres for sale.

Manufacturing and Distribution Facilities

Our equipment manufacturing and repair operations are headquartered in Cisco, Texas. Our Cisco plant has approximately 126,000 square feet of space and, operating at full capacity, is capable of producing up to 30 hydraulic fracturing units per month. At this facility, we also manufacture many of the components used in our hydraulic fracturing units, including fuel tanks, structural brackets, hoses and mufflers. We also have a parts distribution center in Cisco, Texas, which has approximately 35,000 square feet of space.

We currently manufacture the high-pressure hydraulic pumps that are used in our hydraulic fracturing units in an approximately 102,000-square foot facility owned by us in Fort Worth, Texas. In 2011, we purchased an approximately 558,000-square foot manufacturing facility in Fort Worth, Texas. We anticipate moving our manufacturing operations for high-pressure hydraulic pumps to this new facility in 2012 and shortly thereafter our manufacturing of hydration units and blenders. See “—Manufacturing Operations.”

We operate an approximately 348,000-square foot chemical manufacturing and blending facility located on approximately 56 acres owned by us in Chickasha, Oklahoma.

Principal Executive Offices

We maintain principal executive offices in an approximately 60,000-square foot facility leased by us in Fort Worth, Texas. We also maintain an approximately 13,000-square foot facility owned by us in Cisco, Texas.

Sales Offices

We have eight sales offices, which we lease in Fort Worth, Dallas, Houston, San Antonio, Tyler and Midland, Texas, and in Tulsa and Oklahoma City, Oklahoma.

Equipment

The equipment and vehicles we use in our operations have significant value. We currently operate 33 hydraulic fracturing fleets. Each fleet typically consists of eight to 22 hydraulic fracturing units, two or more blenders (one used as a backup), which blend the proppant and chemicals into the hydraulic fluid, sand kings, which are large containers used to store sand on location, various vehicles used to transport sand, chemicals, gels and other materials, various service trucks and a monitoring van equipped with monitoring equipment and computers that control the hydraulic fracturing process. In addition to our hydraulic pumps, other service equipment with measurable horsepower includes acid pumps, nitrogen pumps and smaller hydraulic pumps, called body loads, used in specialized applications. We design and manufacture much of the equipment we use in our operations. Because we have significantly expanded our operations in recent periods by adding new fleets of hydraulic fracturing units, most of our equipment is relatively new. See “—Our Company,” “—Manufacturing Operations” and “—Manufacturing and Distribution Facilities.”

 

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Customers

Our principal customers are independent E&P companies conducting onshore operations in the United States. The following table shows the customers who represented more than 10% of our consolidated gross revenues from our hydraulic fracturing operations in any of the periods indicated below. The loss of any of our largest existing customers could have a material adverse effect on our results of operations.

 

     Percentage of Revenues  
     Year Ended
December 31,
    Six  Months
Ended

June 30,
2011
 

Customer

   2008     2009     2010    

Chesapeake

     17.1     10.6     8.2     15.9