FORM S-1

Large accelerated filer

Accelerated filer

Non-accelerated filer

þ (Do not check if a smaller reporting company)

Smaller reporting company

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

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

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):

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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

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

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.

The Offering

Common stock offered by us

Common stock offered by selling stockholder

Common stock outstanding after the offering

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:

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

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

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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.

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:

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

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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;

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changes in legislation and the regulatory environment;

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

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the loss of any of our key executives;

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continuing or increased competition;

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our inability to fully protect our intellectual property rights;

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

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dependence on a limited number of major customers.

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			Six Months Ended June 30, 2010			January 1 through May 5, 2011			May 6 through June 30, 2011			Six Months Ended June 30, 2011
	(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


	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		Six Months Ended June 30, 2010		January 1 through May 5, 2011		May 6 through June 30, 2011		Six Months Ended June 30, 2011
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.

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			Six Months Ended June 30, 2010			January 1 through May 5, 2011			May 6 through June 30, 2011			Six Months Ended June 30, 2011
										(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.”

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.

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

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.

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.

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:

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

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.

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,

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. 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

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:

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.

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.

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.

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.

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:

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.

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:

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:

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.

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:

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.

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.”

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.

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:

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.

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.

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.”

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.

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:

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:

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.

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.

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.

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:

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.

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):

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

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.

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:

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.

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

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:

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.

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.

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:

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 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.

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

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.

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:

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.

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.

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.

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.

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

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

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.

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

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.

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.

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.”

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.

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.

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

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.

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 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.

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.

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.

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.

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.

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 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

(“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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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).

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.

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

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.

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.

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

Increased Service Intensity and Activity in More Demanding Shale Reservoirs

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.

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

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.

Increase Proppant Production and Distribution and Equipment Manufacturing Capabilities

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.

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

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.

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.

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

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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

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.”

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.

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.

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.

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.

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.

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.

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.”

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.

One of our principal customers, Chesapeake, is also a significant beneficial equity holder in our company and has the right to designate two individuals to serve on our board of directors. See “Risk Factors—Risks Relating to the Offering and Our Common Stock—Our investor group will collectively retain a majority interest in us and have the ability to control all major decisions, and their interests may conflict with the interests of our other stockholders,” “Principal and Selling Stockholders” and “Management—Directors and Executive Officers.”

We purchase some of the parts we use in the fabrication and assembly of our hydraulic fracturing units and certain of the raw materials we use in our operations, such as chemicals and diesel fuel, from a variety of suppliers throughout the United States. 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. We currently have agreements with Caterpillar and Twin Disc providing for delivery of specified numbers of transmissions at set prices during 2011, and agreements with Caterpillar and Cummins providing for delivery of specified numbers of diesel engines at set prices during 2011. We believe we will be able to enter into similar contracts with these manufacturers for future periods. To date, we have generally been able to obtain on a timely basis the equipment, parts and supplies necessary to support our operations. We have experienced some delays in obtaining parts that we use in our manufacturing operations during periods of high demand, and fuel price increases have resulted in significant increases in our operating costs in certain periods. If demand for our services and competition in our industry increase significantly in the future, we could experience delays or increased costs in acquiring new equipment, parts or supplies necessary to expand our business.

See “—Sand Production and Distribution” for information about our sources of supply for the raw sand and resin-coated sand we use as proppants in our hydraulic fracturing operations.

Our competition includes multi-national oilfield service companies as well as regional competitors. Our major multi-national competitors are Halliburton Company, Schlumberger Ltd. and BJ Services Company, a subsidiary of Baker Hughes, each of which has significantly greater financial resources than we do. We believe we are the third largest hydraulic fracturing service company in the United States, based on the total horsepower of our fleets, and that our equipment fleets are significantly newer than the fleets operated by our major

competitors. Our three large multi-national competitors, as well as some smaller companies that we do not consider to be our primary competitors, have more diverse product and service offerings than we do, providing a number of oilfield services and products in addition to well stimulation.

Competition in our industry is based primarily on service quality, timing and availability of equipment and products, particularly proppants, performance history and price. We believe we consistently deliver exceptional service, based in part on the durability of our equipment. Our durable equipment reduces down time due to equipment failure and allows our customers to avoid costs associated with delays in completing their wells. By being able to meet the most demanding pressure and flow rate requirements, our equipment also enables us to operate efficiently in challenging geological environments in which some of our competitors cannot operate effectively.

By fabricating and assembling our own hydraulic fracturing units and by manufacturing many of the parts used in those units, including the hydraulic pumps, we are able to react quickly to conditions encountered in the field to improve our equipment by refining the proprietary designs we use in the manufacturing process. For example, we have improved the durability of our fluid ends by, among other things, modifying the design to decrease the internal pressures experienced during operation and to allow easier access for repairs and maintenance. We have also thickened the walls of our fluid ends and are testing technology that we believe will allow us to harden the metal we use to manufacture the fluid ends and redesigned the power ends of our pumps to make them lighter, which reduces wear and tear on our hydraulic fracturing units during transport. Our in-house manufacturing operations also enable us to replace the fluid ends, which is the part of the hydraulic pump that requires replacement most frequently, and other parts quickly to further minimize down time for our customers. See “—Manufacturing Operations.” We believe that our ability to modify the design of our equipment based on our experience in the field and to repair and replace our fluid ends and other components quickly provides us with a competitive advantage over our competitors who do not manufacture their own equipment.

We believe our chemical blending operations also give us a competitive advantage by giving us the ability to produce some of the most technologically advanced fracturing fluids in the industry. See “—Chemical Blending Operations.”

By owning our own sand mines and processing plants, and an extensive sand distribution network, we are able to ensure a stable supply and ready availability of raw sand. See “—Sand Production and Distribution.” These assets, together with our in-house equipment manufacturing and chemical blending operations, give us a competitive advantage by allowing us to begin work at a customer’s well site more quickly than we would be able to in many cases if we relied on third parties for the equipment and products we use in our hydraulic fracturing operations. This enables us to increase equipment utilization and allows our customers to reduce costs associated with delays in completing their wells.

We believe the relationships we have developed with our customers based on our history of providing exceptional service enhance our ability to obtain additional business from those customers.

Although our strategy is not to compete primarily on the basis of price, our vertically integrated operations allow us to control our costs and to provide our services at competitive prices.

We operate in a highly cyclical industry. The main factor influencing demand for fracturing services is the level of drilling activity by E&P companies, which in turn depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. Demand for oil and natural gas is cyclical and is subject to large and rapid fluctuations. This is primarily because the industry is driven by commodity demand and corresponding price increases. When oil and natural gas price

increases occur, producers increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. The increased capital expenditures also ultimately result in greater production, which historically has resulted in increased supplies and reduced prices that, in turn, tends to reduce demand for oilfield services such as hydraulic fracturing services. For these reasons, our results of operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort period-to-period comparisons of our results of operations.

In general, we believe we have good relations with our employees. None of our employees is currently represented by a union. At July 31, 2011, we had approximately 3,900 employees, including approximately 270 persons serving in management, sales and administrative positions.

We carry a variety of insurance coverages for our operations, and we are partially self-insured for certain claims, in amounts that we believe to be customary and reasonable. However, our insurance may not be sufficient to cover any particular loss or may not cover all losses. Also, insurance rates have in the past been subject to wide fluctuation, and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions.

Our insurance includes coverage for commercial general liability, damage to our property and equipment, pollution liability (covering both third-party liabilities and first-party site specific property damage), workers’ compensation and employer’s liability, auto liability and other risks. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. Specifically, our commercial general liability policy provides for a limit of $1.0 million per occurrence and $2.0 million in the aggregate. Our commercial umbrella policy provides for a limit of $5.0 million per occurrence and $5.0 million in the aggregate with a $100,000 self-insured retention. We also maintain two additional layers of excess liability coverage, with a total limit of $175.0 million per occurrence and $175.0 million in the aggregate.

To cover potential pollution risks, our commercial generally liability policy is endorsed with sudden and accidental coverage, our excess liability policies provide additional limits of liability for covered losses on the commercial general liability policy and we maintain a contractors’ pollution liability program that provides for a total limit of $125.0 million per incident and $125.0 million in the aggregate with a self-insured retention of $250,000 per incident and $1.0 million in the aggregate.

We also maintain site specific pollution insurance that provides for a limit of $5.0 million per incident and $5.0 million in the aggregate with a $25,000 deductible per incident for both on- and off-site cleanup as well as third party property damage and bodily injury. Our site specific pollution coverage affords third-party liability and first party cleanup coverage. Our contractors’ pollution liability insurance covers liabilities associated with our hydraulic fracturing operations in the field, while our site specific pollution insurance covers liabilities arising from insured locations. These insured locations are properties that we own or lease.

Our operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the EPA, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, expenditures associated with exposure to hazardous materials, remediation of contamination, property damage and personal injuries, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental

contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of that person. Strict adherence with these regulatory requirements increases our cost of doing business and consequently affects our profitability. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our business, financial condition and results of operations.

The Comprehensive Environmental Response, Compensation and Liability Act, referred to as “CERCLA” or the Superfund law, and comparable state laws impose strict liability, joint and several liability, or both, without regard to fault, on certain classes of persons that are considered to be responsible for the release of hazardous or other state-regulated substances into the environment. These persons include the current or former owner or operator of the disposal site or the site where the release occurred and the parties that disposed or arranged for the disposal or treatment of hazardous or other state-regulated substances that have been released at the site. Under CERCLA, these persons may be subject to strict liability, joint and several liability, or both, for the costs of investigating and cleaning up hazardous substances that have been released into the environment, damages to natural resources and health studies without regard to fault. In addition, companies that incur liability frequently confront additional claims because neighboring landowners and other third parties often file claims for personal injury and property damage allegedly caused by hazardous or other state-regulated substances or other pollutants released into the environment.

The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, (“RCRA”) generally excludes oil and gas exploration and production wastes (e.g., drilling fluids, produced waters) from regulation as hazardous wastes. However, these wastes remain subject to potential regulation as solid wastes under RCRA and as hazardous waste under other state and local laws. Moreover, wastes from some of our operations (such as our chemical development, blending, and distribution operations) may not qualify for the exemption from regulation as hazardous waste under RCRA. Further, the exemption under RCRA does not alter treatment of the substance under CERCLA.

From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA, the federal Clean Water Act, and analogous state laws. Under these laws or other laws and regulations, we have been and may be required to remove or remediate these materials or wastes and make expenditures associated with personal injury or property damage. At this time, with respect to any properties where materials or wastes may have been released, but of which we have not been made aware, it is not possible to estimate the potential costs that may arise from unknown, latent liability risks.

On March 15, 2011 companion bills entitled the 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 the UIC program in the federal Safe Drinking Water Act (the “SDWA”). 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 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 SDWA. 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. Depending on its results, the EPA study could spur further initiatives to regulate hydraulic fracturing under the SDWA 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.

Our operations are also subject to the federal Clean Water Act and analogous state laws. Under the Clean Water Act, the EPA has, among other measures, adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff and, as part of our overall evaluation of our current operations, we would apply for storm water discharge permit coverage for those properties, and update storm water discharge management practices at some of our facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on us.

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants from specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We are required to obtain federal and state permits in connection with our sand mining and processing activities under applicable laws. These permits impose certain conditions and restrictions 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, or in the permits we operate under, could increase our costs or limit the amount of sand we can process. Additionally, the EPA’s Tier IV regulations apply to certain off-road diesel engines used by us to power equipment in the field. Under these 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 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, Tier IV regulations may result in increased costs as we continue to grow.

E&P activities on federal lands may be subject to the National Environmental Policy Act, (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a

proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our activities and our customers’ current E&P activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Where takings of or harm to species or damages to jurisdictional streams or wetlands habitat or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration activities or seek damages for harm to species, habitat, or natural resources resulting from filling of jurisdictional streams or wetlands or construction or releases of oil, wastes, hazardous substances or other regulated materials.

The EPA has proposed and finalized a number of rules requiring a number of industry sectors to track and report, and, in some cases, control greenhouse gas emissions. The EPA’s Mandatory Reporting of Greenhouse Gases Rule was published in October 2009. This rule requires large sources and suppliers in the United States to track and report greenhouse gas emissions. On November 8, 2010, the EPA finalized a rule that sets forth reporting requirements for the petroleum and natural gas industry. Among other things, this final rule requires persons that hold state permits for onshore oil and gas exploration and production and that emit 25,000 metric tons or more of carbon dioxide equivalent per year to annually report carbon dioxide, methane and nitrous oxide combustion emissions from (1) stationary and portable equipment and (2) flaring. Under the final rule, our customers may be required to include calculated emissions from our hydraulic fracturing equipment located on their well sites in their emission inventory. In June 2010, the EPA’s Greenhouse Gas Tailoring Rule became effective. For this rule to apply initially, the source must already be subject to the Clean Air Act Prevention of Significant Deterioration program or Title V permit program. We are not currently subject to either Clean Air Act program. The EPA and the National Highway Traffic Safety Administration recently announced their intent to propose coordinated rules to regulate greenhouse gas emissions from heavy-duty engines and vehicles, and light-duty vehicles. To date, proposed rules have not been issued. It is unclear whether Congress will take further action on greenhouse gases, for example, to further regulate greenhouse gas emissions or alternatively to statutorily limit the EPA’s authority over greenhouse gases. Even without federal legislation or regulation of greenhouse gas emissions, states may pursue the issue either directly or indirectly. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry and, therefore, could reduce the demand for our products and services.

Climate change regulation may also impact our business positively by increasing demand for natural gas for use in producing electricity and as a transportation fuel. Currently, our operations are not adversely impacted by existing state and local climate change initiatives. At this time, we cannot accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

We seek to minimize the possibility of a pollution event through equipment and job design, as well as through training employees. We also maintain a pollution risk management program if a pollution event occurs. This program includes an internal emergency response plan that provides specific procedures for our employees to follow in the event of a chemical release or spill. In addition, we have contracted with a third-party emergency responder who is available on a 24-hour basis to handle the remediation and clean-up of any chemical release or spill. We carry insurance designed to respond to foreseeable environmental exposures. This insurance portfolio has been structured to address incidents that result in bodily injury or property damage and any ensuing clean up needed at our owned facilities, as a result of the mobilization and utilization of our fleet, as well as any claims resulting from our operations. See “—Insurance.”

We also seek to manage environmental liability risks through provisions in our contracts with our customers that allocate risks relating to surface activities associated with the fracturing process, other than water disposal, to us and risks relating to “down-hole” liabilities to our customers. 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. Our contracts generally require our customers to indemnify us against pollution and environmental damages originating below the surface of the ground or arising out of water disposal, or otherwise caused by the customer, other contractors or other third parties. In turn, we indemnify our customers for pollution and environmental damages originating at or above the surface caused solely by us. We seek to maintain consistent risk-allocation and indemnification provisions in our customer agreements to the greatest extent possible. Some of our contracts, however, contain less explicit indemnification provisions, which typically provide that each party will indemnify the other against liabilities to third parties resulting from the indemnifying party’s actions, except to the extent such liability results from the indemnified party’s gross negligence, willful misconduct or intentional act.

We are subject to the requirements of the federal Occupational Safety and Health Act, commonly referred to as OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Our sand mining operations are subject to the requirements of the Federal Mine Safety and Health Act of 1969 (the “Mine Act”), which imposes comprehensive safety and health standards on all aspects of mining operations. In addition to federal regulatory programs, the states in which our mines are located have programs aimed at improving mine safety and health. In reaction to recent mine accidents, particularly in the coal mining industry, federal and state legislatures and regulatory authorities have increased scrutiny of mine safety matters and passed more stringent laws governing mining. We have received citations from the Mine Safety and Health Administration related to violations of certain Mine Act regulations relating to our operations at our sand mines. These citations generally require the payment of fines, none of which has been material. The aggregate amount of the proposed fines relating to the citations we received during 2010 is less than $25,000.

Our research and development efforts are focused on providing specific solutions to the challenges our customers face when fracturing and stimulating wells. In addition to the design and manufacture of innovative equipment, we have also developed proprietary blends of chemicals that we use in connection with our hydraulic fracturing services. We have filed five patent applications relating to our fracturing methods, including a method for applying nano particles to enhance recovery of hydrocarbons from oil and natural gas reservoirs, for the technology used in our fluid ends, hydraulic pumps and other equipment and for certain of our chemicals. These applications include three U.S. applications and two patent cooperation treaty applications. The patent cooperation treaty applications preserve our right to file certain patent applications in other countries.

We believe the information regarding our customer and supplier relationships are also valuable proprietary assets. We have pending applications and registered trademarks for various names under which our entities conduct business. Except for the foregoing, we do not own or license any patents, trademarks or other intellectual property that we believe to be material to the success of our business.

We are involved in various legal proceedings from time to time in the ordinary course of our business. However, we are not currently involved in any legal proceedings that we believe are likely to have a material adverse effect on our operations or financial condition.

We anticipate that the following persons will serve as our directors and executive officers in the positions indicated. Presently, each of the persons listed as an executive officer in the table below serves in a corresponding position with Frac Tech Services, LLC, and each of the persons listed as a director in the table below currently serves on the board of managers of Frac Tech International, LLC.

Marcus C. Rowland has served as our Chief Executive Officer since May 2011. From November 2010 to May 2011, he served as the President and Chief Financial Officer of our predecessor. Mr. Rowland also served on the board of managers of our predecessor as the designee of Chesapeake from 2006 through October 2010. He served as Chesapeake’s Chief Financial Officer from 1993 to November 2010, Executive Vice President from 1998 to November 2010, Senior Vice President from 1997 to 1998, and Vice President—Finance from 1993 to 1997. Mr. Rowland served as a director of Chesapeake Midstream Partners, L.P. from January 2010 to May 2011. From 1990 until he joined Chesapeake in 1993, Mr. Rowland was Chief Operating Officer of Anglo-Suisse, L.P. assigned to the White Nights Russian Enterprise, a joint venture of Anglo-Suisse, L.P. and Phibro Energy Corporation, a major foreign operation which was granted the right to engage in oil and gas operations in Russia. Prior to his association with White Nights Russian Enterprise, Mr. Rowland owned and managed his own natural gas and oil company and prior to that was Chief Financial Officer of a private exploration company in Oklahoma City from 1981 to 1985. Mr. Rowland has more than 30 years of oilfield business experience.

James Coy Randle, Jr. has served as our President and Chief Operating Officer since May 2011. He served as our Senior Vice President of Operations from March 2009 to May 2011. Mr. Randle joined our company is March 2007 as Southern Division Manager and served as Vice President of Operations from August 2007 to March 2009. Mr. Randle has more than 29 years of oilfield services experience, including 25 years operating and supervising various business units for BJ Services Company, most recently as a District Manager from 2001 to 2007.

Chris Cummins has served as our Senior Vice President of Proppants since May 2011. He served as Vice President of Sales and Marketing for Southern Precision Sands, LLC, our wholly owned subsidiary, from the time he joined our company in October 2008 until May 2011. Prior to joining us, Mr. Cummins served as the Vice President of Sales and Marketing at Atlas Resin Proppants from July 2006 to October 2008. He held positions of increasing responsibility at Oglebay Norton Industrial Sands from 1995 to 2006, most recently serving as Vice President of Sales. Mr. Cummins has more than 35 years of experience in the pressure pumping industry and the proppant business.

Brad Holms has served as our Senior Vice President—Global Business Development and Technology since May 2011. From November 2007 to May 2011, he served as our Senior Vice President of Marketing and Technology. Before joining us, Mr. Holms worked for Schlumberger Limited for 30 years, including predecessor firms, most recently in the position of Global Account Manager. Mr. Holms has more than 34 years of experience in marketing, technology, operations management, global sales and account management.

Kevin McGlinch has served as Senior Vice President of Finance and Treasurer since November 2010. He joined us in September 2008 as our Corporate Controller and served as our Chief Financial Officer from November 2008 to November 2010. During the year and a half prior to joining us, Mr. McGlinch worked for Vought Aircraft Industries, Inc. as their Corporate Controller. Prior to his job at Vought Aircraft, Mr. McGlinch worked for two years as the Controller of EDSCO Fasteners. He has 18 years of finance and accounting experience with leading manufacturers such as Sherwin-Williams, Stanley, Newell Rubbermaid, and Vought Aircraft.

Dan Patterson has served as our Chief Accounting Officer, Senior Vice President of Accounting and Corporate Controller since joining our company in January 2011. From November 2008 to November 2009 he served as Corporate Controller and Chief Financial Officer of Super Plaza Stores, LLC. From September 2006 to November 2008, he served as Corporate Financial Reporting Manager at Commercial Metals Company. From February 2006 to September 2006 he served as a Corporate Technical Accounting Consultant to Flowserve Corp. From August 1988 to February 2006, he worked in the accounting, internal control and operations departments at Albertsons, Inc. Mr. Patterson has over 19 years of diversified experience in SEC reporting, general accounting, financial analysis, performance reporting, auditing and operations.

Robert Pike has served as our Senior Vice President of Sales since joining our company in February 2011. Prior to joining us, he held positions of increasing responsibility at BJ Services Company (acquired by Baker Hughes Incorporated in April 2010) from August 2003 to February 2011, including Senior City Sales Manager and, most recently, Area Sales Manager. From November 2000 to April 2003, he worked for SPS International, most recently as Vice President of Sales and Marketing. Mr. Pike has over 25 years of domestic and international sales and engineering leadership experience with leading companies, including more than 12 years in various engineering and management positions at Halliburton Energy Services.

Charles Veazey has served as our Senior Vice President of Operations since July 2011. Since joining our company, he has served as a Business Development Manager from March 2008 to August 2008 our Mid-Continent Division Manager from September 2008 to April 2009, and Vice President of Operations from April 2009 to July 2011. Mr. Veazey has more than 35 years of experience in our industry. Prior to joining us, he worked for BJ Services Company and its predecessors for more than 28 years, most recently as a Region Manager.

Justin Wilks has served as our Senior Vice President of Logistics since May 2011. He served as President of Vertex Solutions, our wholly owned subsidiary, from March 2010 to May 2011. Mr. Wilks held positions of increasing responsibility from April 1998 to March 2010 at Wilks Masonry, a construction company owned by certain of our former owners, including as President from November 2005 to March 2010.

William A. Hicks has served as our General Counsel and Vice President since joining our company in January 2007. Prior to that, he was a director and shareholder with the Abilene, Texas law firm of McMahon, Surovik, Suttle, PC, where he worked for 26 years. Mr. Hicks is a Fellow in the American College of Trial Attorneys, a Life Fellow in the Texas Bar Foundation, a member of the American Board of Trial Advocates, a member of the Association of Corporate Counsel and a member of the Texas and American Bar Associations. He is licensed in all Texas state courts and Federal District Courts for the Northern and Western Districts of Texas, as well as the Fifth Circuit Court of Appeals.

Domenic J. Dell’Osso, Jr. has served as a director of our company since May 2011 and was a director of our predecessor from October 2010 to May 2011. He is a board designee of Chesapeake. Mr. Dell’Osso is currently Executive Vice President and Chief Financial Officer of Chesapeake, a position he has held since November 2010. Mr. Dell’Osso served as Vice President—Finance of Chesapeake and Chief Financial Officer of

Chesapeake’s wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010. Prior to joining Chesapeake, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from 2006 to August 2008 and Banc of America Securities from 2004 to 2006.

Greg A. Lanham has served as a director of our company since May 2011. Mr. Lanham is a board designee of Temasek. Mr. Lanham is currently the Managing Director for the Energy team at Temasek, a position he has held since September 2009. Prior to joining Temasek, he spent 20 years with Anadarko Petroleum Corporation in positions of increasing responsibility, including President and General Manager of Asian operations, resident Managing Director over all business in East and West Africa, International Engineering Manager, and Planning Manager for all international development projects.

Aubrey K. McClendon has served as a director of our company since May 2011. He is a board designee of Chesapeake. Mr. McClendon has served as Chairman of the Board and Chief Executive Officer of Chesapeake since co-founding the company in 1989. From 1982 to 1989, he was an independent producer of oil and natural gas. Mr. McClendon has also served as a director of the general partner of Chesapeake Midstream Partners, L.P. since 2010.

Goh Yong Siang has served as a director of our company since May 2011. Mr. Goh is a board designee of Temasek. Mr. Goh is currently the Head of Strategic Relations, Head of Australia & New Zealand and Co-Head, Organization & Leadership of Temasek, which he joined in August 2006. Prior to joining Temasek, he spent five years working in private equity with Texas-based companies. Prior to that, he served two years as President of ST Engineering (USA). Mr. Goh was a fighter pilot and served in the Singapore Armed Forces, retiring as Chief of the Air Force in 1998.

Ong Tiong Sin has served as a director of our company since May 2011. Mr. Ong is a board designee of Senja. Mr. Ong is the founder and the Chief Executive Officer of RRJ Capital Ltd (“RRJ Capital”), the investment manager of a $2.3 billion private equity fund established in March 2011 with offices in Hong Kong and Singapore. From 1993 to January 2008, Mr. Ong was an investment banker with Goldman, Sachs & Co. He became a Managing Director of Goldman, Sachs & Co. in 1996 and a partner in 2000. Between 2008 and 2011, Mr. Ong was the Chief Executive Officer of Hopu.

Our certificate of incorporation and bylaws will provide that the board of directors shall consist of not less than directors, nor more than directors, and the number of directors may be changed only by resolution of the board of directors. Our directors will be elected annually to serve until the next meeting of stockholders or until their successors are duly elected and qualified. Upon completion of this offering, we anticipate that we will have directors: Messrs. McClendon, Dell’Osso, Lanham, Goh, Ong and .

Initially, our board of directors will consist of a single class of directors each serving one year terms. We expect that our certificate of incorporation will provide that, once the investor group, which includes Temasek, Chesapeake, Senja, Cowboy Investment and certain other investors, in the aggregate, no longer beneficially owns more than 50% of our outstanding shares of common stock, our board of directors will be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms (other than directors which may be elected by holders of preferred stock, if any).

Based upon the listing standards of the NYSE and SEC regulations, we anticipate that our board of directors will determine that Messrs. are “independent” under the standards of the NYSE. We are currently seeking to add independent directors to our board. Although we have not established any specific objective criteria for service on our board, we anticipate that we will offer the positions to persons who have significant experience relevant to companies in our industry and other qualifications that the existing members of our board believe will enable such persons to make significant contributions to our company. In addition, we will seek to identify candidates to fill the positions who meet the requirements for service on our Audit Committee, as described below.

Prior to the closing of this offering, our board of directors will establish an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee, and may establish such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the responsibilities described below.

We anticipate that the initial members of our Audit Committee will be Messrs. , and , each of whom is financially literate. We anticipate that Mr. will be the Chairman of the committee, and he is an “audit committee financial expert” as described in Item 407(d)(5) of Regulation S-K. We currently intend to rely on the phase-in rules of the SEC and NYSE with respect to the independence of our Audit Committee. These rules permit us to have an Audit Committee that has one member that is independent upon the effectiveness of the registration statement of which this prospectus forms a part, a majority of members that are independent within 90 days thereafter and all members that are independent within one year thereafter. Our Audit Committee will be authorized to assist the board in overseeing the integrity of our financial statements, the qualifications and independence of our independent auditor, the performance of our independent auditor and internal auditors, our compliance with legal and regulatory requirements, our risk exposures and the other responsibilities set forth in its charter.

We anticipate that the initial members of our Compensation Committee will be Messrs. , and , and that Mr. will be the Chairman of the committee. Our Compensation Committee will be authorized to:

We anticipate that the initial members of our Nominating and Corporate Governance Committee will be Messrs. , and , and that Mr. will be the Chairman of the committee. Our Nominating and Corporate Governance Committee will be authorized to:

We anticipate that no past or present employee will be an initial member of our Compensation Committee. We also anticipate that none of our executive officers will serve on the board of directors or compensation committee of any entity that has one or more executive officers serving as a member of our board of directors or Compensation Committee.

To the extent any members of our Compensation Committee and affiliates of theirs have participated in transactions with us, those transactions are described in “Certain Relationships and Related Party Transactions.”

Our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

We did not award any compensation to any non-employee director during 2010, however, we believe that attracting and retaining qualified non-employee directors will be critical to our future growth. Following this offering, our non-employee directors are expected to receive compensation that is commensurate with the compensation that is offered to directors of companies that are similar to ours, including equity-based awards granted under our 2011 Long-Term Incentive Plan. We have not, nor do we expect to, compensate our employee directors for their service on our board of directors. We expect to reimburse our directors for reasonable out-of-pocket expenses that they incur in connection with their service as directors, in accordance with our general expense reimbursement policies.

As a private company, we have established our executive compensation program to attract, motivate and retain our key employees in order to enable us to maximize the profitability and value of our company over the long term. Following this offering, we expect that the Compensation Committee of our board of directors may recommend changes to our executive compensation program. Nonetheless, we expect that our compensation program will continue to be focused on building long-term stockholder value by attracting, motivating and retaining talented, experienced executives and other key employees.

This section provides a historical description and explanation of our compensation program for Messrs. Rowland, Randle, Hicks, McGlinch and Veazey, who we refer to as our “named executive officers.” Each of our named executive officers has historically served as an officer of Frac Tech Services, LLC, our predecessor’s wholly owned subsidiary, and we anticipate that each such person will hold a corresponding position with the registrant upon completion of this offering.

We have historically compensated our named executive officers with base salaries, annual cash bonuses and health, life and other insurance benefits. Additionally, the employment agreements that we have with our named executive officers provide for enhanced payments and benefits in connection with certain termination events and upon the occurrence of a change of control. Following this offering, we expect that these elements, as well as equity-based incentive awards, will constitute the primary elements of our compensation program, although the relative proportions of each element, and the specific plan and award designs, will likely evolve as we become a more established public company.

Base Salary. The minimum annual base salary for each of our named executive officers is set forth in the executive’s employment agreement. In determining our named executive officers’ base salaries, we considered management responsibilities, level of experience and tenure with our company, including our predecessor. For the amounts of base salary that our named executive officers received in 2010, see “—Executive Compensation—Summary Compensation Table.”

Annual Bonus. We do not have a formal bonus plan, but we have historically paid discretionary cash bonuses to our named executive officers and other key employees as we believe annual cash bonuses motivate employees. Annual cash bonuses for 2010 were paid to each named executive officer and were awarded based on a subjective evaluation of the executive’s performance. For the amounts of bonuses paid to our named executive officers in 2010, see “—Executive Compensation—Summary Compensation Table.”

Equity-Based Incentive Awards. We have not historically made grants of equity-based incentive awards, although we granted Mr. Rowland options to purchase membership units in our predecessor during 2010. The options were to vest ratably in three equal annual installments beginning on the first anniversary of the grant date. These options became fully vested, and Mr. Rowland exercised them, in connection with the Acquisition Transaction. See “—Executive Compensation—Summary Compensation Table,” “—Executive Compensation—Grant of Plan-Based Awards,” and “—Executive Compensation—Outstanding Equity Awards at Fiscal Year-End.”

Other Benefits. We have historically provided each of our named executive officers with a company vehicle. We have also provided certain of our named executive officers with limited personal use of company owned, leased or chartered aircraft pursuant to their employment agreements as further described below.

Employee Benefits. We have historically provided health, life and other insurance benefits to our named executive officers on the same basis as our other full-time employees. Our employees are also entitled to make contributions on a pre-tax and post-tax basis to a 401(k) plan and receive matching contributions. Since 2011, we have provided a matching contribution equal to 4% of eligible compensation contributed to the 401(k) plan. Effective January 1, 2012, the matching contribution percentage will be increased to 6% and we will begin supplementing each participant’s account with a discretionary matching contribution after the end of each calendar year. We do not sponsor any defined benefit pension plan or nonqualified deferred compensation arrangements.

The elements of compensation described above under “—Elements of Compensation” and the amounts of compensation for 2010 described below under “—Executive Compensation” were established by the prior majority owners of our predecessor. Following the Acquisition Transaction, Messrs. Rowland and Randle negotiated their compensation and benefits directly with our investor group, and the terms of employment and compensation of our other named executive officers were negotiated by Messrs. Rowland and Randle with such officers.

Following this offering, the compensation of our named executive officers will be determined by the Compensation Committee of our board of directors in consultation with our Chief Executive Officer as to executives other than himself. See “Management—Committees of the Board of Directors—Compensation Committee.”

This section provides information on our named executive officers’ compensation in 2010, except where otherwise indicated.

The following table summarizes the compensation of our named executive officers during the year ended December 31, 2010.

The following table contains information regarding options to purchase membership units awarded to Mr. Rowland during 2010 pursuant to the terms of our predecessor’s 2010 Long-Term Incentive Plan. None of our named executive officers other than Mr. Rowland received grants of plan-based awards during 2010.

The following table contains information regarding unexercised options to purchase membership units outstanding under our predecessor’s 2010 Long-Term Incentive Plan as of December 31, 2010. None of our named executive officers other than Mr. Rowland held any unexercised options as of December 31, 2010.

No options to purchase membership units in our predecessor were exercised nor did any restricted membership units in our predecessor vest during 2010.

We have not maintained and do not currently maintain a defined benefit plan or a supplemental executive retirement plan.

Non-Qualified Defined Contribution and Other Non-Qualified Deferred Compensation Plans

We have not had and do not currently have any defined contribution or other plan that provides for the deferral of compensation on a basis that is not tax qualified.

The table and narrative below quantify and describe the payments and benefits due to each of our named executive officers in the event of a qualifying termination of employment and/or in the event we undergo a change of control. As discussed below under “—New Employment Agreements,” we recently entered into new employment agreements with each of our named executive officers which superseded the prior employment agreements of such persons with our predecessor and we have determined that, rather than disclosing the payments and benefits to which each named executive officer actually would have been entitled to on December 31, 2010 under his former agreement, our potential investors would find it more meaningful if we disclosed the payments and benefits to which each named executive officer would have been entitled under his new employment agreement, had it been in effect on December 31, 2010. A summary of the termination and change of control provisions of our named executive officers’ employment agreements appears immediately following this table. We believe that providing enhanced payments and benefits in connection with certain termination events and upon the occurrence of a change of control is essential to our ability to recruit and retain high level professionals to serve as our executive officers, given the heightened concern for financial stability by many professionals in the energy sector due to the industry’s history of terminating professionals during cyclical downturns and increasing consolidation in the energy sector.

The amounts disclosed in the table below assume that the termination event and/or the occurrence of the change of control occurred on December 31, 2010. We have also assumed that each named executive officer (1) was employed from January 1, 2010 through December 31, 2010, (2) had no accrued vacation as of December 31, 2010 and (3) had no outstanding equity awards as of December 31, 2010, as the registrant had no outstanding equity awards as of that date. In calculating the bonus payments in the table below, we have used the applicable maximum or minimum bonus specified in the executive’s employment agreement, as more fully described below. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time a named executive officer is actually terminated or a change of control actually occurs.

The employment agreements with Messrs. Rowland and Randle contain the following provisions relating to payments due upon termination or in connection with a change of control.

Termination Without Cause or for Good Reason. If the company terminates the executive’s employment without cause or the executive terminates his employment for good reason, then the executive is entitled to receive the following payments and benefits:

The executive is deemed to have been terminated without cause if the executive is terminated for any reason other than:

The executive is deemed to have terminated his employment for good reason if the termination follows:

Termination Due to Incapacity or Death. If the executive’s employment is terminated by the company due to the executive’s incapacity or death, the executive (or his beneficiary or estate, as applicable) is entitled to receive:

The right to compensation for termination by the company without cause or by the executive for good reason is expressly conditioned upon the executive’s execution and non-revocation of the company’s severance and release agreement and the executive’s compliance with all of the provisions of his employment agreement, including all post-employment obligations, which include not competing with the company for two years following termination, non-solicitation of company employees for three years following termination and confidentiality obligations. The right to compensation for termination due to incapacity or death is expressly conditioned upon the execution and non-revocation of the company’s severance and release agreement by the executive, executive’s legal representative, beneficiary or the administrator of executive’s estate, as applicable.

Termination in Connection with a Change of Control. If a change of control of the company occurs and the executive’s employment with the company is terminated without cause or for good reason, then the executive is entitled to receive two times the sum of (a) his then-current base salary, plus (b) the amount of bonuses paid to

the executive during the 12 calendar months immediately preceding the change of control. Additionally, if a change of control occurs, all restricted securities that have been granted to the executive pursuant to his employment agreement will be immediately vested and the company will make a lump sum payment to the executive in an amount equal to the fair market value of the restricted securities.

The occurrence of an initial public offering of the company does not constitute a change of control under the employment agreements.

The employment agreements with Messrs. Hicks, McGlinch and Veazey contain the following provisions relating to payments due upon termination or in connection with a change of control.

The definitions of “cause” and “good reason” in these employment agreements are generally consistent with the definitions of those terms in the employment agreements for Messrs. Rowland and Randle, as described above.

Termination Due to Retirement. If the executive is 55 years or older and voluntarily terminates the agreement with or without cause, he will be eligible for accelerated vesting (as set forth in a retirement matrix attached to the agreement) of unvested equity compensation awarded by the company pursuant to the agreement.

Termination in Connection with a Change of Control. If a change of control of the company occurs and the executive’s employment with the company is terminated, then the executive is entitled to receive an amount equal to 100% of (a) his then-current base salary, plus (b) the amount of bonuses paid to the executive during the 12 calendar months immediately preceding the change of control. Additionally, if a change of control occurs, all equity incentive awards granted to the executive pursuant to his employment agreement shall be immediately vested and the company will make a lump sum payment to the executive in an amount equal to the fair market value (as determined by our board in good faith) of all equity incentive awards granted to the executive pursuant to his employment agreement. These employment agreements contain the same definition of change of control as the employment agreements for Mr. Rowland and Mr. Randle, as generally described above.

The right to compensation for termination by the company without cause, by the executive for good reason or in connection with a change of control is expressly conditioned upon the executive’s execution of the company’s severance agreement and the executive’s compliance with all of the provisions of his employment agreement, including all post-employment obligations such as non-competition, non-solicitation and confidentiality obligations. The right to compensation for termination due to incapacity or death is expressly conditioned upon the execution of the company’s severance agreement by the executive, executive’s legal representative, beneficiary or the administrator of executive’s estate, as applicable.

We recently entered into new employment agreements with each of our named executive officers which supersede the employment agreements that were in place prior to the Acquisition Transaction. The following is a summary of the material terms of the new employment agreements.

We entered into new employment agreements with Mr. Rowland, our Chief Executive Officer, effective August 1, 2011 and with Mr. Randle, our President and Chief Operating Officer, effective July 1, 2011. Each agreement has an initial term of approximately three years and expires on June 30, 2014, with automatic one-year extensions, unless either party provides notice of its desire not to extend the term at least 90 days prior to the applicable expiration date. Each agreement provides for an annual base salary of not less than $800,000, increasing to not less than $1,000,000 in July 2012, and not less than $1,200,000 in July 2013. Each agreement also provides for annual bonus compensation of not less than $250,000, increasing to not less than $300,000 in the second year and not less than $350,000 in the third year, provided that the executive is a full-time employee on the bonus payment date. Mr. Rowland and Mr. Randle are each entitled to receive restricted securities with a minimum value of $1,000,000 in August 2011, a minimum value of $1,500,000 not later than July 1, 2012 and a minimum value of $2,000,000 not later than July 1, 2013. To be eligible for the awards, each executive must be a full-time employee on the grant date. On August 15, 2011, our board granted each of Messrs. Rowland and Randle 1,000,000 restricted units in Frac Tech International, LLC in accordance with the terms of their respective employment agreements. Mr. Rowland’s restricted units vest in three equal installments on July 15, 2012 and

2013 and June 29, 2014. Mr. Randle’s restricted units vest in four equal installments on July 15, 2012 and 2013, and June 29, 2014 and 2015. In connection with our Conversion, these restricted units will convert into restricted shares of our common stock.

Each executive is also entitled to four weeks of paid vacation and health, life and other insurance benefits as we customarily provide to our executive officers. For safety, security and efficiency, each of Mr. Rowland and Mr. Randle is permitted to use aircraft in which we own fractional interests through the NetJets program for personal use up to 75 hours per year. Neither executive is required to reimburse us for any cost related to such use or for guests or family members traveling with him, although each executive will pay all personal income taxes accruing as a result of his personal use of our aircraft. The employment agreements with Messrs. Rowland and Randle also provide for certain benefits upon a termination of employment or in connection with a change of control. These benefits are discussed above under “—Potential Payments upon Termination and Change of Control.”

We also have entered into new employment agreements with Mr. Hicks, our General Counsel and Vice President, effective July 3, 2011, Mr. McGlinch, our Senior Vice President of Finance and Treasurer, effective in September 2011, and Mr. Veazey, our Senior Vice President of Operations, effective July 6, 2011. Each agreement has an initial term of three years with automatic one-year extensions, unless we provide notice to the executive of our desire not to extend the term at least 30 days prior to the applicable expiration date. The automatic extensions may not extend the term of the agreements for a period of longer than three years at any one time. The agreements provide for the following annual base salaries and maximum annual bonuses as a percentage of base salary, provided that in order to receive the bonus, the executive must be a full-time employee of the company on the bonus payment date:

Each of the agreements provide that the executive may be granted restricted securities of the company following the successful consummation of this offering. To be eligible for the awards of restricted securities, each executive must be a full-time employee on the grant date. Each executive is also entitled to 20 days of paid time off and health, life and other insurance benefits as we customarily provide to our executive officers. Mr. Veazey is permitted to use the aircraft in which we own fractional interests through the NetJets program for personal use up to 20 hours per year and is not required to reimburse us for any cost related to such use or for guests or family members traveling with him, although Mr. Veazey will pay all personal income taxes accruing as a result of his personal use of our aircraft. The employment agreements with Messrs. Hicks, McGlinch and Veazey also provide for certain benefits in connection with a change of control. These benefits are discussed above under “—Potential Payments upon Termination and Change of Control.”

Our board of directors plans to adopt, and we expect that our stockholders will approve, a 2011 Long-Term Incentive Plan, or LTIP, to be effective as of the consummation of this offering, in order to attract, motivate and retain the best available personnel for positions of substantial responsibility, and to provide additional incentives to our employees and directors to promote the success of our business. The LTIP will

provide for grants of (a) incentive stock options qualified as such under U.S. federal income tax laws, (b) nonqualified stock options that do not qualify as incentive stock options, (c) stock appreciation rights, or SARs, (d) restricted stock awards, (e) restricted stock units, (f) performance awards, (g) other incentive awards or (h) any combination of such awards.

The LTIP will not be subject to the Employee Retirement Income Security Act of 1974, as amended, or ERISA. The LTIP, for a limited period of time following this offering, will qualify for an exception to the deductibility limitations imposed by Section 162(m) of the Internal Revenue Code. Section 162(m) of the Code imposes a limit of $1,000,000 on the amount that we may deduct for compensation paid to each of our CEO and certain other named executive officers per year; however, if specified conditions are met, some compensation may be excluded from counting against this limit. Compensation that is excluded from the limit includes compensation that meets the requirements under Section 162(m) for “qualified performance-based” compensation. The LTIP is designed to allow for awards that constitute “qualified performance-based compensation” and are deductible for federal income tax purposes although our Compensation Committee may determine to issue awards that do not meet the requirements for deductibility. Initially, we will rely on a transition exemption from Section 162(m) for the LTIP that applies to compensation plans adopted prior to an initial public offering. The transition exemption for the plan will terminate at the time of our annual meeting that occurs after the third calendar year following the year of our initial public offering or, if earlier, at the time we materially modify the plan.

Shares Available. The maximum aggregate number of shares of our common stock that may be reserved and available for delivery in connection with awards under the LTIP is , subject to adjustment in accordance with the terms of the LTIP. If common stock subject to any award is not issued or transferred, or ceases to be issuable or transferable for any reason, including (a) shares of common stock subject to an award that is cancelled, forfeited or settled in cash and (b) shares of common stock withheld to pay the exercise price of or to satisfy the withholding obligations with respect to an award, those shares of common stock will again be available for delivery under the LTIP to the extent allowable by law. The maximum number of shares of common stock that may be subject to nonqualified stock options and SARs granted under the LTIP to any one participant during a fiscal year will be shares. The maximum aggregate number of shares that may be issued under the LTIP through incentive stock options will be shares.

Eligibility. Any individual who provides services to us, including officers, employees, non-employee directors and consultants (each, an “Eligible Person”), will be eligible to participate in the LTIP.

Administration. The Compensation Committee will administer the LTIP pursuant to its terms, except to the extent our board of directors chooses to take action under the LTIP. The Compensation Committee or the board may delegate authority to make certain awards under the LTIP to our Chief Executive Officer or another executive officer. Unless otherwise limited, the Compensation Committee will have broad discretion to administer the LTIP, including the power to determine to whom and when awards will be granted, to determine the amount of such awards (measured in cash, shares of common stock or otherwise), to proscribe and interpret the terms and provisions of each award, to accelerate the exercise terms of any award, to delegate duties under the LTIP and to execute all other responsibilities permitted or required under the LTIP.

Terms of Options. The Compensation Committee may grant (a) incentive stock options that comply with Section 422 of the Code to our employees and (b) nonqualified options to any Eligible Person. The exercise price for an option must not be less than the greater of (a) the par value per share of common stock or (b) the fair market value per share of common stock as of the date of grant. Options may be exercised on such terms as the Compensation Committee determines, but not later than ten years from the date of grant.

Terms of SARs. SARs may be awarded in connection with or separate from an option. A SAR is the right to receive an amount equal to the excess of the fair market value of one share of our common stock on the date of exercise over the grant price of the SAR. SARs will be exercisable on such terms as the Compensation

Committee determines. The term of an SAR will be for a period determined by the Compensation Committee but will not exceed ten years. SARs may be paid in cash, common stock or a combination of cash and common stock, as determined by the Compensation Committee in the award agreement.

Restricted Stock Awards. A restricted stock award is a grant of shares of common stock subject to a risk of forfeiture, restrictions on transferability and any other restrictions determined by the Compensation Committee. Except as otherwise provided under the terms of the LTIP or an award agreement, the holder of a restricted stock award may have rights as a stockholder, including the right to vote or to receive dividends (subject to any mandatory reinvestment or other requirements determined by the Compensation Committee). Unless otherwise determined by the Compensation Committee, a restricted stock award will be forfeited and reacquired by us upon termination of employment. Common stock distributed in connection with a stock split or stock dividend, and other property distributed as a dividend, may be subject to the same restrictions and risk of forfeiture as the restricted stock with respect to which the distribution was made.

Restricted Stock Units. Restricted stock units are rights to receive cash, common stock or a combination of cash and common stock at the end of a specified period. Restricted stock units may be subject to restrictions, including a risk of forfeiture, as determined by the Compensation Committee. Restricted stock units may be satisfied by cash, common stock or any combination of cash and common stock, as determined by the Compensation Committee. Unless otherwise determined by the Compensation Committee, restricted stock units will be forfeited upon termination of a participant’s employment. The Compensation Committee may, in its sole discretion, grant dividend equivalents with respect to restricted stock units.

Performance Awards. The LTIP will provide for the grant of performance awards that may be granted in the form of cash, common stock or a combination of cash and common stock. Each performance award will set forth (a) the amount, including a target and maximum amount if applicable, the recipient may earn in the form of cash or shares of common stock or a formula for determining that amount, (b) the performance criteria and level of achievement versus the criteria that will determine the amount of cash payable or number of shares of our common stock to be granted, issued, retained and/or vested, (c) the performance period over which performance is to be measured, (d) the timing of any payments to be made, (e) restrictions on the transferability of the award and (f) such other terms and conditions as our Compensation Committee may determine.

Other Awards. The LTIP will permit our Compensation Committee to grant awards in addition to those described above, subject to applicable legal limitations and the terms of the LTIP. Such awards may include common stock awarded as a bonus, dividend equivalents, convertible or exchangeable debt securities, other rights convertible or exchangeable into common stock, purchase rights for common stock, awards with value and payment contingent upon our performance or any other factors determined by the Compensation Committee. The Compensation Committee will determine terms and conditions of all such awards. Long-term cash awards also may be made under the LTIP. Cash awards also may be granted as an element of or a supplement to any awards permitted under the LTIP. Awards may also be granted in lieu of obligations to pay cash or deliver other property under the LTIP or under other plans or compensation arrangements, subject to any applicable provision under Section 16 of the Exchange Act.

A “related party transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, and which involves an amount exceeding $120,000, and in which any related party had, has or will have a direct or indirect material interest. A “related party” means:

Our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, the Audit Committee will review all material facts of all related party transactions and either approve or disapprove entry into the related party transaction, subject to certain limited exceptions. In determining whether to approve or disapprove entry into a related party transaction, the Audit Committee shall take into account, among other factors, the following: (1) whether the related party transaction is on terms no less favorable to us than terms generally available to an unaffiliated third party under the same or similar circumstances and (2) the extent of the related party’s interest in the transaction. Further, the policy will require that all related party transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations.

The following transactions were entered into prior to our establishment of an Audit Committee or the adoption of the approval procedures described above.

One of our major customers, Chesapeake, holds a 30% beneficial ownership interest in us. See “Business—Customers” and “Principal and Selling Stockholders.” In fiscal years 2008, 2009 and 2010, we received approximately $97.8 million, $41.2 million and $107.7 million, respectively, in revenues from Chesapeake for hydraulic fracturing services.

We entered into a master service agreement with Chesapeake in April 2007. This agreement governs the performance of services and/or the supply of materials or equipment to Chesapeake, the specifics of which are handled under subsequent written purchase or work orders. The agreement contains standard terms and provisions, including insurance requirements and confidentiality obligations and allocates certain operational risks through indemnity provisions. In April 2011, we entered into a Master Frac Services Agreement with Chesapeake under which Chesapeake agreed to provide a guaranteed rate of return on a portion of our fleets in return for a structured fee for exclusive use of those fleets. The agreement provides that Chesapeake will enter into backstop contracts for use of those fleets at market rates, but if our gross profit margin on such fleets is less than 10% in any quarter, Chesapeake will pay us an amount equal to such deficiency. Conversely, if the gross profit margin on such fleets is more than 20% in any quarter, we will pay Chesapeake an amount equal to such

excess. Chesapeake is not required to enter into a backstop contract if (i) it is already under contract with us for 30% or more of the total horsepower in all of our fleets, (ii) 50% or more of the total number of our fleets are being utilized by Chesapeake or (iii) the number of our fleets is equal to or greater than the backstopped fleet maximum set forth in the agreement. This agreement is subject to the terms of our master service agreement with Chesapeake and expires on December 31, 2014.

Prior to the Acquisition Transaction on May 6, 2011, Chesapeake owned 25.8% of the outstanding membership interests in our predecessor. In connection with the Acquisition Transaction, Chesapeake contributed such interest to us in exchange for approximately $206 million in cash and limited liability company units representing 30% of our outstanding limited liability company units, and became party to our limited liability company agreement described below.

The amended and restated limited liability agreement governing Frac Tech International, LLC was entered into on May 6, 2011 in connection with the Acquisition Transaction among Maju Investments (Mauritius) Pte Ltd, an indirect wholly owned investment holding company of Temasek, Chesapeake Operating, Inc., a wholly owned subsidiary of Chesapeake, Senja and certain other investors. Pursuant to the agreement, such investors were issued limited liability company units. Temasek and Chesapeake each have the right to designate two persons to serve on our board of managers for as long as they own an equity interest in us. Messrs. Lanham and Goh are currently serving as Temasek’s designees on our board of managers, and Messrs. McClendon and Dell’Osso are currently serving as Chesapeake’s designees. Senja has the right to designate one person to serve on our board of managers for as long as it owns an equity interest in us. Mr. Ong is currently serving as Senja’s designee on our board of managers.

Our limited liability agreement permits the board of managers to determine the amount of excess cash and other property of the company and distribute such excess to the members in accordance with their ownership percentage. The agreement also requires the company to make distributions of cash to its members in an amount and at such times as the board of managers reasonably determines are appropriate to permit the members to pay U.S. federal and applicable state income taxes on their respective share of the company’s net taxable income. We intend to make such distributions, which are commonly referred to as “tax distributions,” prior to the effectiveness of our Conversion so that the amounts distributed will not be subject to additional taxes that would be incurred if we were to make such distributions after we cease to be a pass-through entity as a result of the Conversion. Although the amount of the federal income taxes that will be payable by our beneficial owners in respect of our earnings for such periods will not be known until after the Conversion, the amount of such tax distributions will be based on our estimated taxable income for such periods and we anticipate that the aggregate amount of such tax distributions will be approximately $ million. We expect to fund the distributions with cash flow from operations.

Our limited liability company agreement imposes a number of restrictions on the issue and transfer of units. Our limited liability company agreement generally requires a member proposing to transfer units to first offer such units to all other members during a 30 day period. If not all of the member’s units are purchased by other members pursuant to such right of first offer, the other members may invoke “tag-along rights” to sell their units to the third party purchasing the transferring member’s units, on the same terms. Members holding more than 75% of outstanding units who receive a bona fide offer to purchase their units from a non-affiliated purchaser may exercise “drag-along” rights to require all other members to sell their units to such purchaser on terms at least as favorable as and simultaneous with the sale by such members. Our limited liability company agreement grants members preemptive rights to acquire units or securities convertible into units that we propose to issue in order to maintain the same percentage of the total outstanding membership interest owned by them prior to such issuance. Members under the limited liability company agreement are not required to make additional capital contributions but may, with the approval of the other members, make such additional contributions in the form of a loan or for additional units.

In connection with the Conversion that will occur prior to the consummation of this offering, all of the limited liability company units in Frac Tech International, LLC will be exchanged for shares of common stock of FTS International, Inc., the limited liability company agreement of Frac Tech International, LLC will be terminated and FTS International, Inc. will be governed by a new certificate of incorporation and bylaws. See “History and Conversion.”

We plan to enter into a registration rights agreement with our existing pre-offering stockholders. These stockholders will be entitled to demand registration rights, including the right to demand that a shelf registration statement be filed, and “piggyback” registration rights, for their shares of our common stock, and any shares acquired by such persons under benefit plans maintained by us or our affiliates. In order to exercise their demand for registration, stockholders who hold, individually or as a group, more than a specified percentage of the shares of our common stock outstanding at the time of exercise must deliver a written request to us. Until we become eligible to use Form S-3 for a registration of shares of our common stock, these stockholders will have the right to exercise demand rights for an agreed number of separate registrations. After we become eligible to use Form S-3 for a registration of shares of our common stock, these stockholders will have the right to exercise demand rights for an additional number of separate registrations, less the number of registrations that were effected prior to such date as a result of the exercise of such demand rights.

We expect that the registration rights agreement will provide that if our board of directors determines that it would be in our best interests, we may delay any demand registration for a period not to exceed 90 days, and such deferral may only be made by us once. Further, (1) we are not required to comply with any registration demand unless the anticipated aggregate offering amount equals or exceeds $50.0 million; (2) we will not be required to effect a demand registration within 180 days after the effective date of the registration statement of our initial public offering or 60 days after the effective date of a previous demand registration, other than a shelf registration, and (3) we will not be required to effect more than two demand registrations during the first 12 months the registration rights agreement is effective or more than three demand registrations during any subsequent 12-month period. In addition, these stockholders will have the right to participate in any public offering of our common stock, other than an offering under a registration statement on Form S-4 or Form S-8 or any other forms not available for registering capital stock for sale to the public, subject to marketing considerations as determined by our managing underwriter for that offering and execution of a lock-up agreement.

We will pay all expenses in connection with any registration under the registration rights agreement and provide customary indemnification. We anticipate that the registration rights described above will begin from the closing date of this offering and will cease to apply to a particular share of common stock after it is, among others, (1) sold pursuant to a registration statement under the Securities Act; (2) sold pursuant to Rule 144 under the Securities Act (or any successor provisions) or (3) otherwise transferred under circumstances where the subsequent public distribution of such shares will not require registration or qualification under the Securities Act or any similar state law. All the members of our board of directors may be deemed to beneficially own or control shares of our common stock and may therefore personally benefit from the registration rights agreement. See “Principal and Selling Stockholders.”

We have entered into certain transactions with Wilks Masonry Corporation, a Texas corporation, including transactions pursuant to which that company provided construction-related services and masonry services in connection with the construction of certain of our facilities. During the years ended December 31, 2008, 2009 and 2010, we paid $9.0 million, $1.2 million and $21.9 million, respectively, to Wilks Masonry. During the year ended December 31, 2008, Wilks Masonry made payments to us for equipment or property rentals in the amount of approximately $2.2 million. In the year ended December 31, 2009, Wilks Masonry paid us approximately $92,000 in reimbursements for shared services such as insurance costs. During the year ended

December 31, 2010, Wilks Masonry paid us approximately $70,000 for the purchase of shop supplies and equipment and $111,000 in reimbursements for shared services such as insurance costs. Justin Wilks, our Senior Vice President of Logistics, was the President of Wilks Masonry until March 2010 and is the son and nephew of its sole owners, who were the prior majority owners and executive officers of our predecessor. See “Management — Directors and Executive Officers.”

Frac Tech Services, LLC was originally formed as a Texas limited partnership in August 2000 and began providing hydraulic fracturing services to E&P companies in 2002. Since then, we have undertaken several reorganization transactions as a result of which (i) that company was converted to a Texas limited liability company, (ii) Frac Tech Holdings, LLC, a Texas limited liability company, was established as its direct parent entity and (iii) all of the other entities through which we conduct business became direct or indirect wholly owned subsidiaries of Frac Tech Holdings, LLC and Frac Tech Services, LLC.

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, 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.

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.” In connection with our Conversion, the current owners of the outstanding limited liability company units of Frac Tech International, LLC will exchange such units for shares of common stock of FTS International, Inc. After our Conversion, FTS International, Inc., which is the issuer of the common stock offered by this prospectus, will be the parent company of all of our subsidiaries and will own the assets and conduct the business described in this prospectus. The chart below depicts our organizational structure after giving effect to our Conversion and our initial public offering. For more information, see “Principal and Selling Stockholders.”

Prior to the consummation of this offering, we will convert into a Delaware corporation and each outstanding limited liability company unit of Frac Tech International, LLC will be converted into shares of common stock of FTS International, Inc. See “History and Conversion.”

The table below sets forth information regarding the beneficial ownership of the common stock of FTS International, Inc. as of , 2011, on a pro forma basis giving effect to the Conversion, by (i) each beneficial owner of more than 5% of our outstanding common stock, (ii) each director of FTS International, Inc., (iii) each of our named executive officers, and (iv) all executive officers and directors as a group. As of , 2011, on the basis stated above, there were shares of our common stock outstanding. The table also sets forth information regarding the shares of our common stock that will be offered and sold by the selling stockholder in this offering. The ownership percentages after the offering are based on the issuance and sale by us of shares of common stock in this offering and the sale by the selling stockholder of outstanding shares of common stock in the offering, assuming no exercise of the underwriters’ over-allotment option. After the offering, there will be shares of our common stock outstanding.

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all common stock shown as beneficially owned by them, subject to community property laws where applicable. Unless otherwise indicated, the address for each director and executive officer listed is: c/o 777 Main Street, Suite 3000, Fort Worth, Texas 76102.

The authorized capital stock of the company will consist of shares of common stock, par value $0.001 per share, and shares of preferred stock, par value $0.001 per share.

The following summary of the capital stock and certificate of incorporation and bylaws of FTS International, Inc. does not purport to be complete and is qualified in its entirety by reference to the provisions of our certificate of incorporation and bylaws, which will be filed as exhibits to the registration statement of which this prospectus is a part.

Except as provided by law or in a preferred stock designation, holders of common stock will be entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and will not have cumulative voting rights. Except as otherwise required by law, holders of common stock, as such, will not be entitled to vote on any amendment to the certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to the certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the General Corporation Law of the State of Delaware, or DGCL. Subject to preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock will be entitled to receive ratably such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock will be fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable. The holders of common stock will not have preferences or rights of conversion, exchange, pre-emption or other subscription rights. There will be no redemption or sinking fund provisions applicable to the common stock. In the event of any liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets that are remaining after payment or provision for payment of all of our debts and obligations and after liquidation payments to holders of outstanding shares of preferred stock, if any.

Our certificate of incorporation will authorize our board of directors without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock covering up to an aggregate of shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Delaware Law, Our Certificate of Incorporation and Our Bylaws

Some provisions of Delaware law contain, and our certificate of incorporation and our bylaws described below will contain, provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise; or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

We will expressly elect not to be governed by the “business combination” provisions of Section 203 of the DGCL regulating corporate takeovers. At any time after our investor group no longer beneficially owns at least 25% of the outstanding shares of our common stock, our election to “opt out” shall be automatically withdrawn, and we will thereafter be governed by such provisions of Section 203 of the DGCL.

In general, the “business combination” provisions of Section 203 of the DGCL prohibit a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

In general, Section 203 defines an interested stockholder as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by any of these entities or persons.

A Delaware corporation may “opt out” of Section 203 with an express provision in its original certificate of incorporation or an express provision in its certificate of incorporation or bylaws resulting from amendments approved by the holders of at least a majority of the corporation’s outstanding voting shares.

We anticipate that, upon the completion of this offering, our certificate of incorporation and bylaws will contain certain provisions that could make it more difficult for a third party to acquire control of us. These provisions may:

Our certificate of incorporation will limit the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a Delaware corporation will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our certificate of incorporation and bylaws will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our certificate of incorporation and bylaws will also permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision in our certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

We intend to apply to list our common stock on the NYSE under the symbol “ .”

Prior to this offering, there has been no public market for our common stock. Future sales of our common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect market prices prevailing from time to time. As described below, only a limited number of shares, other than shares sold in this offering, will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Upon the closing of this offering, we will have issued and outstanding an aggregate of shares of common stock. Of these shares, all of the shares of common stock to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of common stock held by existing stockholders will be deemed “restricted securities” as such term is defined in Rule 144. The restricted securities were issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

Under the provisions of Rule 144 and Rule 701 under the Securities Act, all of the shares of our common stock (excluding the shares to be sold in this offering and unvested restricted shares held by members of management) will be available for sale in the public market upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus (subject to certain exceptions and extensions) and when permitted under Rule 144.

We, all of our directors, officers and principal stockholders have agreed not to sell or otherwise transfer or dispose of any common stock for a period of 180 days from the date of this prospectus, subject to certain exceptions and extensions. See “Underwriting” for a description of these lock-up provisions.

In general, under Rule 144 as currently in effect, once we have been a reporting company subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act for 90 days, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

Once we have been a reporting company subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act for 90 days, a person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability

of current public information about us. Messrs. Rowland and Randle will be entitled to sell the restricted shares of common stock that they will receive in connection with the Conversion in exchange for the restricted units they own currently following the vesting of such shares in accordance with these provisions of Rule 144 and subject to the lock-up restrictions discussed above. Mr. Rowland’s restricted units vest in three equal installments on July 15, 2012, July 15, 2013 and June 29, 2014, and Mr. Randle’s restricted units vest in four equal installments on July 15, 2012, July 15, 2013, June 29, 2014 and June 29, 2015. See “Executive Compensation and Other Information—Executive Compensation—New Employment Agreements—Mr. Rowland and Mr. Randle.”

We intend to file a registration statement on Form S-8 under the Securities Act to register stock issuable under our 2011 Long-Term Incentive Plan. This registration statement is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above. Upon the closing of this offering, we will have shares of common stock reserved and available for future issuance as stock options, restricted stock or other equity-based incentive awards under our 2011 Long-Term Incentive Plan. For a description of the terms of this plan, see “Executive Compensation and Other Information—Executive Compensation—2011 Long-Term Incentive Plan.”

We expect to grant to certain of our existing stockholders the right to require us to register the shares of common stock held by them under certain circumstances after consummation of this offering. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

In connection with the Acquisition Transaction, Frac Tech International, LLC, as borrower, entered into a $1.5 billion senior secured term loan and related security and other agreements with a syndicate of financial institutions as lenders and Bank of America, as administrative agent, which we refer to as our “senior secured term loan.” Borrowings under the senior secured term loan, which matures on May 6, 2016, were used to finance the Acquisition Transaction.

Our obligations under the senior secured term loan are secured by a first priority security interest in all assets of Frac Tech International, LLC, including all of the equity interests in Frac Tech Holdings, LLC.

The senior secured term loan bears interest at a rate per annum equal to LIBOR, plus an applicable margin based on our leverage. Interest is due and payable quarterly. We must repay the senior secured term loan in quarterly installments, in the amount of $3,750,000, with the balance due upon final maturity on May 6, 2016. 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). Our senior secured term loan also requires that we make quarterly principal payments in an amount equal to the maximum amount we are permitted to distribute under the indenture governing our senior notes, less certain amounts.

The senior secured term loan contains a number of covenants that restrict our ability and the ability of our subsidiaries to incur additional indebtedness; create liens on assets; make investments, loans or advances; engage in mergers or consolidations; sell assets; make acquisitions; pay dividends and make distributions or repurchase our and their equity interests; engage in certain transactions with affiliates; and make capital expenditures. These covenants are subject to a number of qualifications and exceptions.

In addition, our senior secured term loan requires us to maintain an interest coverage ratio of 2.50:1.00 and a maximum consolidated leverage ratio of 3.75:1.00 through December 30, 2011, decreasing by .25 each quarter thereafter until June 30, 2012 to 3.00:1.00.

The senior secured term loan contains customary events of default, including (i) defaults under indebtedness with an aggregate principal amount exceeding $10 million that results in the acceleration of the maturity thereof, or permits the holders (or any trustee or agent) to accelerate the maturity thereof, or constitutes the failure to pay required amounts when due and (ii) the existence of unsatisfied judgments (for a period of 30 days from entry) in excess of $10 million.

We intend to use all of the net proceeds from this offering to repay outstanding borrowings under our senior secured term loan, as required under its terms. See “Use of Proceeds.”

On November 12, 2010, Frac Tech Services, LLC and Frac Tech Finance, Inc., as co-issuers, completed a private offering of $550.0 million aggregate principal amount of 7.125% Senior Notes due 2018, which we refer to as our “senior notes,” for total cash proceeds of approximately $539.0 million, after deducting commissions. The senior notes mature on November 15, 2018 and bear interest at 7.125% per annum, payable semi-annually in arrears on May 15 and November 15, beginning May 15, 2011. The senior notes are unsecured and are guaranteed by Frac Tech Services, LLC’s existing and future subsidiaries, subject to certain exceptions.

may redeem some or all of the senior notes at a price equal to 100% of the principal amount plus a make-whole premium determined pursuant to a formula set forth in the indenture governing the senior notes, plus accrued and unpaid interest. On or after November 15, 2014, we may redeem some or all of the senior notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on November 15 of the years indicated below:

Upon a change of control, as defined in the indenture, we are required to make an offer to purchase the senior notes at a price equal to 101% of the principal amount plus accrued and unpaid interest. The Acquisition Transaction constituted a change of control, and as a result, on May 6, 2011, the co-issuers commenced an offer to purchase any and all of the outstanding senior notes at a price equal to 101% of the principal amount plus accrued and unpaid interest. On June 7, 2011, the co-issuers announced that $320,000 principal amount of the outstanding senior notes had been validly tendered and accepted for purchase in such tender offer.

The indenture governing the senior notes contains covenants that limit the ability of the co-issuers and the ability of certain of their subsidiaries to incur or guarantee additional indebtedness or issue certain preferred stock; pay dividends on capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with affiliates; and merge or consolidate with other companies or transfer all or substantially all assets. These covenants are subject to a number of qualifications and exceptions.

The indenture contains customary events of default, including (i) defaults under indebtedness with an aggregate principal amount of at least $25 million that results in the acceleration of the maturity thereof or constitutes the failure to pay required amounts when due and (ii) the existence of unsatisfied judgments (for a period of 60 days from entry) in excess of $25 million.

Pursuant to a Registration Rights Agreement among the co-issuers, the guarantors and the initial purchasers of the senior notes, dated November 12, 2010, the co-issuers and the guarantors of the senior notes agreed to file with the SEC on or prior to 240 days after the closing of the senior notes offering (or July 11, 2011) a registration statement with respect to an offer to exchange the senior notes and the related guarantees for identical new notes and guarantees registered under the Securities Act (or, under certain circumstances, a shelf registration statement covering resales of the senior notes and related guarantees). We have not filed such registration statement, therefore, we are required to pay additional interest. The rate of additional interest is 0.25% per annum for the first 90-day period immediately following the deadline to file the registration statement, and such rate will increase by an additional 0.25% per annum with respect to each subsequent 90-day period, up to a maximum additional interest rate of 1.0% per annum.

On August 5, 2011, Frac Tech Services, LLC entered into a $100 million revolving credit facility and related security and other agreements with a syndicate of financial institutions as lenders and Royal Bank of Canada, as administrative agent, which we refer to as our “revolving credit facility.” The revolving credit facility includes a sublimit of $50 million for the issuance of letters of credit and allows for one or more swingline loans from Wells Fargo Bank, N.A. up to an aggregate amount of $20 million provided certain conditions are met. The revolving credit facility will mature on August 5, 2016.

Loans under the revolving credit facility will be available for Frac Tech Services, LLC to borrow up to the lesser of (a) the $100 million commitment by the lenders (which may be reduced in certain circumstances)

and (b) the borrowing base. The borrowing base is based on certain eligible inventory and accounts receivable of Frac Tech Services, LLC and its wholly owned subsidiaries, with certain discounts applied, and will be redetermined from time to time.

Frac Tech Services, LLC’s obligations under the revolving credit facility are secured, by a first-priority security interest in all of its and each of its wholly owned subsidiaries’ accounts receivable, inventory and proceeds thereof. None of the assets of Frac Tech Holdings, LLC or Frac Tech International, LLC are pledged as security for the revolving credit facility.

The revolving credit facility is unconditionally guaranteed by each of Frac Tech Services, LLC’s wholly owned domestic restricted subsidiaries.

Loans under the revolving credit facility will bear interest, at Frac Tech Services, LLC’s option, at:

Swingline loans bear interest at a rate equal to the higher of (1) the U.S. prime rate, (2) the federal funds effective rate plus 0.50% and (3) adjusted one-month LIBOR plus 1% per annum, in each case plus an applicable margin.

The applicable margin for the revolving credit facility is subject to change pursuant to a pricing grid based on availability under the revolving credit facility. In addition, the credit agreement provides for customary commitment fees and letter of credit fees under the revolving credit facility.

The revolving credit facility contains a number of covenants that restrict the ability of Frac Tech Services, LLC and its restricted subsidiaries to incur additional indebtedness; create liens on assets; make investments, loans or advances; engage in mergers or consolidations; sell assets; make acquisitions; pay dividends and make distributions or repurchase their equity interests; and engage in certain transactions with affiliates. These covenants are subject to a number of qualifications and exceptions.

The revolving credit facility contains customary events of default, including (i) defaults under indebtedness with an aggregate principal amount exceeding $25 million that results in the acceleration of the maturity thereof, or permits the holders (or any trustee or agent) to accelerate the maturity thereof, or constitutes the failure to pay required amounts when due and (ii) the existence of unsatisfied judgments (for a period of 60 days from entry) in excess of $25 million.

The following is a summary of the material United States federal income tax consequences of the purchase, ownership and disposition of our common stock to a non-U.S. holder as of the date hereof. For the purpose of this discussion, a non-U.S. holder is any beneficial owner of our common stock (other than a partnership or entity treated as a partnership for United States federal income tax purposes) that is not for United States federal income tax purposes any of the following:

If a partnership (including any entity or arrangement treated as a partnership for United States federal income tax purposes) holds our common stock, the U.S. federal income tax treatment of a partner in the partnership generally will depend on the status of the partner and upon the activities of the partnership. Accordingly, we urge partnerships that hold our common stock and partners in such partnerships to consult their tax advisors as to the particular U.S. federal income tax consequences applicable to them.

This summary assumes that a non-U.S. holder will hold our common stock issued pursuant to the offering as a capital asset (generally, property held for investment). This summary does not address all aspects of United States federal income taxation and does not deal with foreign, state, local, alternative minimum tax or other tax considerations that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address United States federal income tax considerations that may be relevant to non-U.S. holders that may be subject to special treatment under United States federal income tax laws, including, without limitation, United States expatriates, insurance companies, tax-exempt or governmental organizations, dealers in securities or currency, banks or other financial institutions, traders in securities that mark-to-market, stockholders that hold our common stock as a result of a constructive sale, stockholders who acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan, and stockholders that hold our common stock as part of a hedge, straddle, appreciated financial position, synthetic security, conversion transaction or other integrated investment or risk reduction transaction. Furthermore, this summary is based on current provisions of the Code and Treasury Regulations and administrative and judicial interpretations thereof, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect.

We have not sought any ruling from the Internal Revenue Service (the “IRS”) with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS will agree with such statements and conclusions. INVESTORS CONSIDERING THE PURCHASE OF COMMON STOCK SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE UNITED STATES FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES ARISING UNDER THE LAWS OF ANY STATE, LOCAL OR FOREIGN TAXING JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.

We currently intend to retain future earnings, if any, to finance the expansion of our business. In addition, Frac Tech Services, LLC’s indenture governing its senior notes limits its ability to make distributions. If we make cash or other property distributions on our common stock, such distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under United States federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will constitute a return of capital and will first reduce the non-U.S. holder’s adjusted tax basis in our common stock, but not below zero, and then will be treated as gain realized from the sale or other disposition of our common stock and will be treated as described under “Gain on Disposition of Common Stock” below.

Any dividend paid to a non-U.S. holder of our common stock generally will be subject to United States withholding tax either at a rate of 30% of the gross amount of the dividend or such lower rate as may be specified by an applicable income tax treaty. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide us (i) a valid IRS Form W-8BEN (or applicable successor form) properly certifying qualification for the reduced rate or (ii) in the case of payments made outside the United States to an offshore account (generally, an account maintained by you at an office or branch of a bank or other financial institution at any location outside the United States), other documentary evidence establishing an entitlement to the lower treaty rate in accordance with applicable U.S. Treasury Regulations.

Dividends paid to a non-U.S. holder that are effectively connected with the conduct of a trade or business by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are attributable to a United States permanent establishment or fixed base of the non-U.S. holder) generally are exempt from the withholding tax described above and instead will be subject to United States federal income tax on a net income basis at the regular graduated United States federal income tax rates in the same manner as if the non-U.S. holder were a United States person as defined under the Code. In such case, we will not be required to withhold United States federal income tax if the non-U.S. holder complies with applicable certification and disclosure requirements. In order to obtain this exemption from withholding tax, a non-U.S. holder must provide us with an IRS Form W-8ECI (or applicable substitute or successor form) properly certifying eligibility for such exemption. Any such effectively connected dividends received by a foreign corporation may be subject to an additional “branch profits tax” at a rate of 30% or such lower rate as may be specified by an applicable income tax treaty. Non-U.S. holders are urged to consult with their tax advisors regarding any applicable income tax treaties that may provide different rules.

Any gain realized on the disposition of our common stock by a non-U.S. holder generally will not be subject to United States federal income tax unless:

A non-U.S. holder who has gain that is described in the first bullet point immediately above will be subject to tax on the net gain derived from the disposition under regular graduated United States federal income

tax rates in the same manner as if it were a United States person as defined under the Code. In addition, a non-U.S. holder described in the first bullet point immediately above that is a foreign corporation may be subject to the branch profits tax equal to 30% of its effectively connected earnings and profits or at such lower rate as may be specified by an applicable income tax treaty.

A non-U.S. holder who meets the requirements described in the second bullet point immediately above will be subject to a flat 30% tax on the gain derived from the disposition, which may be offset by United States source capital losses, even though the individual is not considered a resident of the United States.

With respect to our status as a USRPHC, we do not believe that we currently are, and do not expect to be for the foreseeable future, a USRPHC for United States federal income tax purposes. You should be aware, however, that the determination of whether we are a USRPHC depends on the fair market value from time to time of our interests in real property (and certain associated personal property, including property used on our real property interests to extract natural deposits) located within the United States relative to our other business assets. There can be no assurance that we will not become a USRPHC in the future. In the event we do become a USRPHC, so long as our common stock is regularly traded on an “established securities market” within the meaning of the applicable U.S. Treasury Regulations, a non-U.S. holder will not be subject to U.S. federal withholding tax on the sale or other disposition of its shares of our common stock and any gain realized on such sale or other disposition would only be subject to U.S. federal income tax if the selling non-U.S. holder actually or constructively holds more than five percent of our common stock at any time during the shorter of the five-year period preceding the date of disposition or the holder’s holding period.

Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our common stock.

Generally, we must report annually to the IRS and to each non-U.S. holder the amount of dividends paid to such non-U.S. holder, the name and address of the recipient, and the amount, if any, of tax withheld with respect to those dividends. These information reporting requirements apply even if withholding was not required. Pursuant to tax treaties or other agreements, the IRS may make its reports available to tax authorities in the recipient’s country of residence.

Payments of dividends to a non-U.S. holder will be subject to backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption, for example, by properly certifying its non-United States status on an IRS Form W-8BEN or another appropriate version of IRS Form W-8. Notwithstanding the foregoing, backup withholding will apply if either we or our paying agent has actual knowledge, or reason to know, that the beneficial owner is a United States person that is not an exempt recipient.

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected outside the United States by or through a foreign office of a broker generally will not be subject to information reporting or backup withholding. However, information reporting (but not backup withholding) will apply to those payments if the broker does not have documentary evidence that the holder is a non-U.S. holder, an exemption is not otherwise established, and the broker has certain relationships with the United States.

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a United States office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption, for example, by properly certifying its non-United States status on an IRS Form W-8BEN or another appropriate version of IRS Form W-8. Notwithstanding the foregoing, information reporting and backup withholding will apply if the broker has actual knowledge, or reason to know, that the holder is a United States person that is not an exempt recipient.

Backup withholding is not an additional tax. Rather, the United States income tax liability of persons subject to backup withholding will be reduced by the amount of tax withheld. If withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Under recently enacted legislation and administrative guidance, the relevant withholding agent may be required to withhold 30% of any dividends paid after December 31, 2013 and the proceeds of a sale of our common stock paid after December 31, 2014 to (i) a foreign financial institution unless such foreign financial institution agrees to verify, report and disclose its United States accountholders and meets certain other specified requirements or (ii) a non-financial foreign entity that is the beneficial owner of the payment unless such entity certifies that it does not have any substantial United States owners or provides the name, address and taxpayer identification number of each substantial United States owner and such entity meets certain other specified requirements. Investors should consult their own tax advisors regarding this legislation.

Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co., Citigroup Global Markets Inc. and Credit Suisse Securities (USA) LLC are acting as representatives of each of the underwriters named below. Subject to the terms and conditions set forth in an underwriting agreement among us, the selling stockholder and the underwriters, we and the selling stockholder have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us and the selling stockholder, the number of shares of common stock set forth opposite its name below.

Subject to the terms and conditions set forth in the underwriting agreement, the underwriters have agreed, severally and not jointly, to purchase all of the shares sold under the underwriting agreement if any of these shares are purchased. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the nondefaulting underwriters may be increased or the underwriting agreement may be terminated.

We and the selling stockholder have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

The underwriters are offering the shares, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the shares, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officer’s certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

The representatives have advised us and the selling stockholder that the underwriters propose initially to offer the shares to the public at the public offering price set forth on the cover page of this prospectus and to dealers at that price less a concession not in excess of $ per share. The underwriters may allow, and the dealers may reallow, a discount not in excess of $ per share to other dealers. After the initial offering, the public offering price, concession or any other term of the offering may be changed.

The following table shows the public offering price, underwriting discount and proceeds before expenses to us. The information assumes either no exercise or full exercise by the underwriters of their over-allotment option.

The expenses of the offering, not including the underwriting discount, are estimated at $ and are payable by us and the selling stockholder. The selling stockholder will be responsible for the underwriting discounts with respect to their 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 and the selling stockholder have granted an option to the underwriters, exercisable for 30 days after the date of this prospectus, to purchase up to additional shares at the public offering price, less the underwriting discount. The underwriters may exercise this option solely to cover any over-allotments. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the underwriting agreement, to purchase a number of additional shares proportionate to that underwriter’s initial amount reflected in the above table.

At our request, the underwriters have reserved for sale, at the initial public offering price, up to shares offered by this prospectus for sale to employees, directors and other persons associated with us who have expressed an interest in purchasing common stock in the offering. If these persons purchase reserved shares, this will reduce the number of shares available for sale to the general public. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same terms as the other shares offered by this prospectus.

We and the selling stockholder, our executive officers and directors and certain of our other existing security holders have agreed not to sell or transfer any common stock or securities convertible into, exchangeable for, exercisable for, or repayable with common stock, for 180 days after the date of this prospectus without first obtaining the written consent of Merrill Lynch, Pierce, Fenner & Smith Incorporated. Specifically, we and these other persons have agreed, with certain limited exceptions, not to directly or indirectly

This lock-up provision applies to common stock and to securities convertible into or exchangeable or exercisable for or repayable with common stock. It also applies to common stock owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition. In the event that either (x) during the last 17 days of the lock-up period referred to above, we release

earnings results or material news or a material event relating to us occurs or (y) prior to the expiration of the lock-up period, we announce that we will release earnings results during the 16-day period beginning on the last day of the lock-up period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the date of release of the earnings or the occurrence of the material news or material event unless Merrill Lynch, Pierce, Fenner & Smith waives, in writing, such extension.

We intend to apply to list the shares on the NYSE under the symbol “ .” In order to meet the requirements for listing on that exchange, the underwriters have undertaken to sell a minimum number of shares to a minimum number of beneficial owners as required by that exchange.

Before this offering, there has been no public market for our common stock. The initial public offering price will be determined through negotiations among us, the selling stockholder and the representatives. In addition to prevailing market conditions, the factors to be considered in determining the initial public offering price are

An active trading market for the shares may not develop. It is also possible that after this offering the shares will not trade in the public market at or above the initial public offering price.

The underwriters do not expect to sell more than 5% of the shares in the aggregate to accounts over which they exercise discretionary authority.

Until the distribution of the shares is completed, SEC rules may limit underwriters and selling group members from bidding for and purchasing our common stock. However, the representatives may engage in transactions that stabilize the price of the common stock, such as bids or purchases to peg, fix or maintain that price.

In connection with the offering, the underwriters may purchase and sell our common stock in the open market. These transactions may include short sales, purchases on the open market to cover positions created by short sales and stabilizing transactions. Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ over-allotment option described above. The underwriters may close out any covered short position by either exercising their over-allotment option or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they

may purchase shares through the over-allotment option. “Naked” short sales are sales in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common stock in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of shares of common stock made by the underwriters in the open market prior to the completion of the offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of our common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common stock. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

In connection with the offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking, financial advisory and other commercial dealings in the ordinary course of business with us or our affiliates. They have received, or may in the future receive, customary fees and commissions for these transactions.

In addition, in the ordinary course of their business activities, the underwriters and their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates, including portions of the senior secured term loan being repaid with the proceeds of this offering. Certain of the underwriters or their affiliates that have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. Typically, such underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities, including potentially the notes offered hereby. Any such short positions could adversely affect future trading prices of the notes offered hereby. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), no offer of shares may be made to the public in that Relevant Member State other than:

provided that no such offer of shares shall require us or the representatives to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive.

Each person in a Relevant Member State (other than a Relevant Member State where there is a Permitted Public Offer) who initially acquires any shares or to whom any offer is made will be deemed to have represented, acknowledged and agreed that (A) it is a “qualified investor” within the meaning of the law in that Relevant Member State implementing Article 2(1)(e) of the Prospectus Directive, and (B) in the case of any shares acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, the shares acquired by it in the offering have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than “qualified investors” as defined in the Prospectus Directive, or in circumstances in which the prior consent of the Subscribers has been given to the offer or resale. In the case of any shares being offered to a financial intermediary as that term is used in Article 3(2) of the Prospectus Directive, each such financial intermediary will be deemed to have represented, acknowledged and agreed that the shares acquired by it in the offer have not been acquired on a non-discretionary basis on behalf of, nor have they been acquired with a view to their offer or resale to, persons in circumstances which may give rise to an offer of any shares to the public other than their offer or resale in a Relevant Member State to qualified investors as so defined or in circumstances in which the prior consent of the representatives has been obtained to each such proposed offer or resale.

We, the representatives and their affiliates will rely upon the truth and accuracy of the foregoing representation, acknowledgement and agreement.

This prospectus has been prepared on the basis that any offer of shares in any Relevant Member State will be made pursuant to an exemption under the Prospectus Directive from the requirement to publish a prospectus for offers of shares. Accordingly any person making or intending to make an offer in that Relevant Member State of shares which are the subject of the offering contemplated in this prospectus may only do so in circumstances in which no obligation arises for us or any of the underwriters to publish a prospectus pursuant to Article 3 of the Prospectus Directive in relation to such offer. Neither we nor the underwriters have authorized, nor do they authorize, the making of any offer of shares in circumstances in which an obligation arises for us or the underwriters to publish a prospectus for such offer.

For the purpose of the above provisions, the expression “an offer to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe the shares, as the same may be varied in the Relevant Member State by any measure implementing the

Prospectus Directive in the Relevant Member State and the expression “Prospectus Directive” means Directive 2003/71/EC (including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member States) and includes any relevant implementing measure in the Relevant Member State and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.

In addition, in the United Kingdom, this document is being distributed only to, and is directed only at, and any offer subsequently made may only be directed at persons who are “qualified investors” (as defined in the Prospectus Directive) (i) who have professional experience in matters relating to investments falling within Article 19 (5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Order”) and/or (ii) who are high net worth companies (or persons to whom it may otherwise be lawfully communicated) falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This document must not be acted on or relied on in the United Kingdom by persons who are not relevant persons. In the United Kingdom, any investment or investment activity to which this document relates is only available to, and will be engaged in with, relevant persons.

This prospectus has not been approved by or registered with the Securities and Futures Commission of Hong Kong or the Registrar of Companies of Hong Kong. The shares will not be offered or sold in Hong Kong other than (a) to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571) of Hong Kong and any rules made under that Ordinance; or (b) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies Ordinance (Cap. 32) of Hong Kong or which do not constitute an offer to the public within the meaning of that Ordinance. No advertisement, invitation or document relating to the shares which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) has been issued or will be issued in Hong Kong or elsewhere other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance and any rules made under that Ordinance.

The shares have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (Law No. 25 of 1948, as amended) and, accordingly, will not be offered or sold, directly or indirectly, in Japan, or for the benefit of any Japanese Person or to others for re-offering or resale, directly or indirectly, in Japan or to any Japanese Person, except in compliance with all applicable laws, regulations and ministerial guidelines promulgated by relevant Japanese governmental or regulatory authorities in effect at the relevant time. For the purposes of this paragraph, “Japanese Person” shall mean any person resident in Japan, including any corporation or other entity organized under the laws of Japan.

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act (Chapter 289) (the “SFA”), (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA. Where the shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited

investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, then shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the securities under Section 275 except: (i) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (ii) where no consideration is given for the transfer; or (iii) by operation of law.

The shares may not be publicly offered in Switzerland and will not be listed on the SIX Swiss Exchange (“SIX”) or on any other stock exchange or regulated trading facility in Switzerland. This document has been prepared without regard to the disclosure standards for issuance prospectuses under art. 652a or art. 1156 of the Swiss Code of Obligations or the disclosure standards for listing prospectuses under art. 27 ff. of the SIX Listing Rules or the listing rules of any other stock exchange or regulated trading facility in Switzerland. Neither this document nor any other offering or marketing material relating to the shares or the offering may be publicly distributed or otherwise made publicly available in Switzerland.

Neither this document nor any other offering or marketing material relating to the offering, us, the shares have been or will be filed with or approved by any Swiss regulatory authority. In particular, this document will not be filed with, and the offer of shares will not be supervised by, the Swiss Financial Market Supervisory Authority FINMA (“FINMA”), and the offer of shares has not been and will not be authorized under the Swiss Federal Act on Collective Investment Schemes (“CISA”). The investor protection afforded to acquirers of interests in collective investment schemes under the CISA does not extend to acquirers of shares.

This prospectus supplement relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (“DFSA”). This prospectus supplement is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus supplement nor taken steps to verify the information set forth herein and has no responsibility for the prospectus supplement. The shares to which this prospectus supplement relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this prospectus supplement you should consult an authorized financial advisor.

The validity of the shares of common stock offered by this prospectus will be passed upon for FTS International, Inc. by Bracewell & Giuliani LLP, Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Shearman & Sterling LLP, New York, New York.

The audited consolidated financial statements of Frac Tech Holdings, LLC, as of December 31, 2009 and 2010 and for each of the three years in the period ending December 31, 2010 included in this prospectus and elsewhere in this registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon authority of said firm as experts in accounting and auditing in giving said reports.

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to us and the common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in that prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of this contract, agreement or other document. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Section of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference facility. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is http://www.sec.gov.

After we have completed this offering, we will file annual, quarterly and current reports, proxy statements and other information with the SEC. After completion of this offering, we expect our website to be located at http://www.fractech.net, and we expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may read and copy any reports, statements or other information on file at the public reference rooms. You can also request copies of these documents, for a copying fee, by writing to the SEC, or you can review these documents on the SEC’s website, as described above. In addition, we will provide electronic or paper copies of our filings free of charge upon request.

We have audited the accompanying consolidated balance sheets of Frac Tech Holdings, LLC, a Texas limited liability company (the “Company”), and subsidiaries as of December 31, 2009 and 2010, and the related consolidated statements of operations, owners’ equity and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal controls over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Frac Tech Holdings, LLC as of December 31, 2009 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

The accompanying notes are an integral part of these consolidated financial statements.

NOTE 1—DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This description of business and summary of significant accounting policies is presented to assist the reader in understanding our consolidated financial statements. These consolidated financial statements and notes are representations of our management who is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America (“US GAAP”) and have been consistently applied in all material respects in the preparation of these consolidated financial statements. In the opinion of management, all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation have been included.

In these notes, references to “the Company,” “we,” “us,” “our,” etc. are to the consolidated group (discussed under “Consolidation” below).

Frac Tech Holdings, LLC, a Texas limited liability company (“FTH”), provides hydraulic fracturing services to oil and natural gas producing companies through Frac Tech Services, LLC, a Texas limited liability company (“FTS”), and its direct and indirect subsidiaries. Prior to January 1, 2010, FTS was a Texas limited partnership and FTH held a 1% general partner interest in FTS. Effective January 1, 2010, the owners of FTH assigned the remaining 99% ownership of FTS to FTH and FTS was converted to a Texas limited liability company. Additionally, effective September 30, 2010, our owners assigned all ownership interests of certain related entities to us, all of which were also under common control. As a result of these assignments, these entities, including entities that were previously consolidated under Financial Accounting Standards Board (“FASB”) Interpretation No. 46R (FIN 46), Consolidation of Variable Interest Entities, an Interpretation of APB No. 51 (which is now incorporated into ASC 810) became our wholly owned subsidiaries. The historical consolidated balance sheets, and the historical statements of operations, owners’ equity and cash flows have all been presented as if the reorganization of these entities took place as of the beginning of the earliest period presented.

The Company’s services are provided during well completion or during attempts to re-stimulate wells that have experienced production declines. Since 2003, service capacity has been expanded by the continuing addition of equipment. At the end of December 2010, we were providing hydraulic fracturing services out of nine districts: Artesia, New Mexico; Shreveport, Louisiana; Hearne, Texas; Longview, Texas; Odessa, Texas; Pleasanton, Texas; Vernal, Utah; Williamsport, Pennsylvania; and Washington, Pennsylvania. Subsequent to December 31, 2010, we opened new district offices in Elk City, Oklahoma, Minot, North Dakota and Aledo, Texas. Within our consolidated group, we build hydraulic fracturing units and various other smaller pieces of equipment that are essential parts of the hydraulic fracturing business. We produce from our own mines and processing plants the majority of the raw sand and resin-coated sand we use as proppants, and we transport most of the raw sand and other products to job sites by rail and truck using our distribution network. We also blend a portion of the chemicals we use in our operations at our chemical blending facility, located in Chickasha, Oklahoma, using our own proprietary formulas.

On July 1, 2009, the Financial Accounting Standards Board (“FASB”) instituted a new referencing system which codifies, but does not amend, previously existing US GAAP. The FASB Accounting Standards

Codification (“ASC”) is now the single authoritative source for US GAAP. Although the implementation of ASC has no impact on the financial statements, certain references to authoritative US GAAP literature within the footnotes have been changed to cite the appropriate ASC content.

These consolidated financial statements include all wholly owned subsidiaries. In addition, we review our relationships with other entities to assess whether we are the primary beneficiary of a variable interest entity. If the determination is made that we are the primary beneficiary, then that entity is consolidated in accordance with ASC 810, Consolidation (“ASC 810”). All material intercompany balances are eliminated upon consolidation.

Revenues are recognized as services are completed. With respect to our hydraulic fracturing services, we recognize revenue and invoice our customers upon the completion of each fracturing stage. We typically complete one or more fracturing stages per day during the course of a job. A stage is considered complete when we have met the specifications set forth in our contract with the customer for the number of hours our equipment is in use or the volume of sand used, or when the pressure exceeds the maximum specified in the contract for our equipment. Invoices typically include an equipment charge determined by applying a base rate for the amount of time the equipment is in operation, a mobilization charge (typically only for the first stage in a job) based on the distance equipment and products are transported to the job site, and product charges for sand, chemicals and other products actually consumed during the course of providing our services.

With respect to sales of sand or other products to third parties, which constitute less than one percent of revenues for all years presented, we recognize revenue upon shipment of the products from our facilities.

Trade accounts receivable are reported at net realizable value consisting of amounts billed less an allowance for doubtful accounts. Most areas in which we operate have provisions for a mechanic’s lien against the property on which the service is performed if such lien is filed within a specified time-frame. Determination of when receivables are past due is generally based on the age of the receivable with over 90 days deemed to be of concern.

We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s credit worthiness, and the condition of the general economy and the industry as a whole. We write off accounts when they are determined to be uncollectible.

Fixed assets include land, facilities and office equipment owned by us, our hydraulic fracturing units and other service equipment, vehicles and transportation equipment, and construction in process. Fixed asset additions are recorded at cost. Costs of hydraulic fracturing units we fabricate and assemble consist of materials, components, labor, and overhead. Land costs include the purchase price, plus zoning and other costs to prepare it for its intended purpose, and any improvements other than buildings. An allocable amount of interest on borrowings is capitalized for self-constructed assets and equipment during their construction period.

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 over their estimated useful life. 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 approximately $6,700 of fluid ends with a useful life of less than 12 months. Beginning October 1, 2010, we have charged the cost of fluid ends added as replacement parts to cost of revenues upon installation.

Management is responsible for reviewing 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.

Inventories consist of both raw materials and work in process. This includes sand and chemicals which are used in providing hydraulic fracturing services and components and parts used in manufacturing and assembly. Because we mine a portion of the sand used in our operations, the ending value of inventory contains certain extraction costs, which include labor, freight and overhead. Inventories are carried at the lower of cost or market value determined on a first-in-first-out basis, except sand and chemicals, which are determined on a weighted average cost basis. Raw materials are valued at cost, including freight, and work in process is valued at cost plus labor and overhead.

We are treated as a partnership for federal income tax purposes. As such, we generally do not directly pay income taxes on our income or benefit from losses. Instead, our income and other tax attributes are passed through to our owners for federal and where applicable, state income tax purposes. The provision for income taxes is for the Texas margin tax which is deemed to be an income tax and the Alabama income tax.

We adopted the provisions of ASC 740, Income Taxes (“ASC 740”), on January 1, 2007. Previously, we had accounted for tax contingencies in accordance with ASC 450, Contingencies (“ASC 450”). As required by the uncertain tax position guidance in ASC 740, 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. At the adoption date, we applied the uncertain tax position guidance in ASC 740 to all tax positions for which the statute of limitations remained open. Since adoption, there were no financial statement benefits or obligations recognized related to uncertain tax positions.

These financial statements have been prepared in anticipation of a proposed initial public offering of the common stock of our parent entity. In connection with its initial public offering, that entity will convert into a Delaware corporation and will be treated as a corporation under the Internal Revenue Code and will be subject to federal income taxes. Accordingly, a pro forma income tax provision has been disclosed as if we were a corporation for all periods presented. We have computed pro forma tax expense using a 35% corporate-level federal tax rate. The effective tax rate includes a corporate level state income tax rate with consideration to apportioned income for each state of operation. This combined rate is adjusted for permanent differences in accordance with ASC 740.

All highly liquid investments with an original maturity of three months or less when acquired are considered to be cash equivalents. The Company will occasionally hold cash deposits in financial institutions that exceed federally insured limits. The Company believes its risk of loss associated with these accounts to be remote.

Other assets subject to amortization include software costs being amortized using the straight-line method over three years to seven years. Amortization costs for 2008, 2009 and 2010 totaled $1,285, $1,909 and $3,061, respectively. Also included in the balance of other assets is $13,343 in deferred financing costs incurred in connection with the issuance of senior notes in November 2010.

In accordance with ASC 805, Business Combinations (“ASC 805”), the acquisition method of accounting requires the excess of purchase price paid over the estimated fair value of identifiable tangible and intangible net assets of acquired businesses to be recorded as goodwill. Under the provisions of ASC 350, Goodwill and Other (“ASC 350”), goodwill is not amortized, and instead, is tested at least annually for impairment. The Company assesses its goodwill for impairment at December 31. As of December 31, 2010 and for the year then ended, no impairment of goodwill was recognized.

We have used interest rate swaps to manage risks related to interest rate movements on our prior term loan and a portion of our prior revolver, both of which had floating interest rates. Our interest rate risk management strategy is to stabilize cash flow requirements by maintaining interest rate swap contracts to convert portions of our variable-rate debt to fixed rates. We do not use derivative financial instruments for speculative or trading purposes.

Interest rate swaps are contracts in which a series of interest cash flows or payments are exchanged over a prescribed period. Changes in the fair values of the instruments we use are recognized in earnings in the current period.

We account for these derivative financial instruments in accordance with ASC 815, Derivatives and Hedging (“ASC 815”). Accordingly, the derivative financial instruments are reflected on the balance sheets at their fair values, in accordance with ASC 820, Fair Value Measurements and Disclosures (“ASC 820”), as discussed in Note 8.

All interest rate swap liabilities were repaid using proceeds from our November 2010 senior notes offering. See Note 7.

We collect and remit sales tax on revenues in jurisdictions where our services are taxable. We pay use taxes to appropriate taxing authority on our taxable purchases. We pay federal excise tax, federal heavy use tax, and report fuel taxes on our fleets of hydraulic fracturing units. Our accounting policy is to exclude tax collected and remitted from revenue and cost of sales.

Loans from members represent advances made on a line of credit established between the Company and its former majority owners. The total of the two lines of credit are $10,000, of which $1,846 and $0 was outstanding as of December 31, 2009 and 2010, respectively. The lines bear interest at the rate of 6.0%. At December 31, 2009 there were subordinated notes and loans between related parties and the Company totaling $8,260. The notes bear interest at rates ranging from 4.04% – 6.0%. All loans from members were repaid using proceeds from our November 2010 senior notes offering. See Note 7.

The Company’s cash, accounts receivable, accounts payable and accrued expenses all approximate fair value due to the relative short term nature of the related account. Our outstanding term loans, revolving credit facility, and advances from members all bear interest rates comparable to prevailing market terms and therefore the outstanding balances approximate fair value.

Amounts attributable to depreciation and amortization charges have been separately stated in our consolidated statements of operations for all periods presented. Previously, depreciation and amortization charges were included as a component of costs of revenues and other expenses, respectively.

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of these financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

At December 31, 2009 and 2010, we had receivables totaling $73,649 and $233,262, net of allowance for bad debts, which is inclusive of $14,629 and $31,303 of trade accounts receivable that is recorded in amounts due from related parties. At December 31, 2009 and 2010, we also had non-trade accounts receivable of $1,410

and $1,191, respectively. Collection of receivables generally occurs between 30 and 60 days after the invoice date. At December 31, 2009 and 2010, respectively, our allowance for bad debts was $3,620 and $6,717. Total bad debt expense for 2008, 2009 and 2010 was $1,121, $1,312 and $2,476, respectively.

Inventories as of December 31, 2009 and 2010 consisted of the amounts in the following table.

The following is a summary of fixed assets as of December 31, 2009 and 2010. Depreciation expense totaled $67,915, $89,239, and $114,915 in 2008, 2009 and 2010, respectively.

The estimated useful life of service equipment placed into service on or after October 1, 2010 ranges from 30 months to ten years. Service equipment used in our hydraulic fracturing services was previously depreciated over a period of ten years. Effective October 1, 2010, these items are being depreciated over a period of seven years. High-pressure iron, which is also included in service equipment, has an estimated useful life of 30 months. Also included in the balance of service equipment is the cost of manufacturing equipment which the Company utilizes for the manufacture of our service equipment components. This manufacturing equipment has a useful life ranging from five to ten years.

The change in accounting estimate associated with the reduction of estimated useful lives of our service equipment resulted in additional depreciation of approximately $10,400 being recognized in the fourth quarter that would not have been recognized under our previous capitalization policies associated with service equipment.

equipment. During that same period, we capitalized approximately $6,700 of fluid ends with a useful life of less than 12 months. Beginning October 1, 2010, we have charged the cost of fluid ends added as replacement parts to cost of revenues upon installation. The remaining carrying value of the replacement fluid ends in service as of September 30, 2010, which was approximately $8,000, will be depreciated over the weighted average remaining useful life, which was approximately 12 months as of September 30, 2010.

The impact of the change in accounting estimate related to the useful life assessment of our fluid ends resulted in approximately $3,200 of cost that was recorded as repairs and maintenance expense during the fourth quarter that otherwise would have been capitalized under our previous capitalization policies for fluid ends.

For the years ended December 31, 2008, 2009 and 2010, we capitalized interest of approximately $1,000, $500 and $1,500, respectively.

When we order equipment from manufacturers, we are often required to pay a deposit (advance) against the total cost of the order as part of the acceptance of the order. Occasionally, we are required to make progress payments as manufacturing milestones are reached.

During the twelve months ended December 31, 2010, the company recognized approximately $9,400 in impairment of service equipment. The impairment was the result of increased utilization of our equipment in more demanding shale reservoirs that resulted in the replacement of equipment earlier than anticipated. As a result of the use of our equipment in more demanding shale reservoirs, we have made changes to our capitalization policy which are more fully described in Note 1, effective October 1, 2010.

A portion of the equipment that was impaired during the twelve months ended December 31, 2010 was also placed into service during 2010 or within one year from that date. This equipment was comprised substantially of replacement fluid ends, which were previously capitalized over a term of one to two years.

We recorded a goodwill impairment charge in 2008 as a result of closing a business we had purchased to obtain priority rights to purchase certain equipment. The operation that we discontinued had an insignificant amount of assets and liabilities at the time it ceased operations.

Other accrued liabilities as of December 31, 2009 and 2010 consisted of the following:

In January 2007, we entered into a senior secured revolving credit facility (our “prior revolver”) with a group of banks to create a revolving line of credit. The original maturity date of the revolver was January 2010. As of December 31, 2009, we were not in compliance with certain covenants and therefore we entered into an amendment and forbearance agreement and subsequently amended and restated the prior revolver in its entirety in May 2010. Subsequent to this date, and prior to December 31, 2010, we issued the senior notes described below and paid off the prior revolver in its entirety.

Senior Notes—On November 12, 2010, FTS and Frac Tech Finance, Inc., a wholly owned subsidiary of FTS, as co-issuers, completed a private offering of $550,000 aggregate principal amount of 7.125% Senior Notes due 2018 (“senior notes”). Frac Tech Finance, Inc. subsequently changed its name to Frac Tech Services, Inc. The senior notes mature on November 15, 2018 and bear interest at 7.125% per annum, payable semi-annually in arrears on May 15 and November 15, beginning May 15, 2011. The senior notes are unsecured and are guaranteed by FTS’s existing and future subsidiaries, subject to certain exceptions. In connection with our issuance of the senior notes, we incurred $13,343 of financing charges, which have been deferred and will be amortized over the life of the senior notes.

The proceeds from our senior notes offering were used to pay off our existing revolver, loans from members, and certain term installment notes. Additionally, $200,000 was used as a return of capital to our prior equity owners.

On or before November 15, 2013, we may redeem up to 35% of the senior notes with proceeds of certain equity offerings at a redemption price of 107.125% of the principal amount plus accrued and unpaid interest. Prior to November 15, 2014, we may redeem some or all of the senior notes at a price equal to 100% of the principal amount plus a make-whole premium determined pursuant to a formula set forth in the indenture governing the senior notes, plus accrued and unpaid interest. On or after November 15, 2014, we may redeem all or part of the senior notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on November 15 of the years indicated below:

Upon a change of control, as defined in the indenture, we are required to make an offer to purchase the senior notes at a price equal to 101% of the principal amount plus accrued and unpaid interest.

The indenture governing the senior notes contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness or issue certain preferred stock; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. As of December 31, 2010, we were in compliance with all covenants.

a registration statement with respect to an offer to exchange the senior notes and the related guarantees for identical new notes and guarantees registered under the Securities Act (or, under certain circumstances, a shelf registration statement covering resales of the senior notes and related guarantees).

The following is a summary of our total obligations, excluding the revolver, as of December 31, 2009 and December 31, 2010.

Maturities for our debt including our senior notes as of December 31, 2010 are as follows:

During 2007, we entered into three interest rate swap agreements related to variable rate borrowings. One agreement was matched with a term note payable in the amount of $15,000 with an interest rate of LIBOR plus 0.85% and a maturity date of December 29, 2016. To minimize the effect of market changes we entered into an interest rate swap agreement under which we pay interest at a fixed rate of 5.95%. The notional amount of this swap declines directly in step with the principal payments on the loan. The Company terminated this swap agreement in November 2010 using proceeds from the senior notes offering.

The other two agreements were related to a total of $140,000 of Eurodollar borrowings under our revolving line of credit. These borrowings float with the LIBOR rate. These two swap agreements matured in September 2010 and provided for us to pay interest at fixed rates of 4.79% on $40,000 and 4.925% on $100,000.

Effective January 1, 2008, we adopted ASC 820 for all financial instruments. ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. Level 2 inputs are inputs observable for similar assets and liabilities. We consider the interest rate swap agreements Level 2 valuations since the value of these derivatives are derived from assumptions from or supported by data that is generally observable in the marketplace. Level 3 utilizes significant unobservable inputs. We currently do not have any fair value measurements within the scope of ASC 820 considered as Level 1 or Level 3 inputs.

Although these three swap agreements were related to our borrowings and were not held for trading purposes, they were classified as mark-to-market derivatives. As such, the effect of changes in the swaps’ fair values and their cash flow effects were included in interest expense until the date the swap agreements matured or terminated.

All interest rate swap liabilities were repaid using proceeds from our November 2010 senior notes offering.

We lease certain administrative and sales offices and operational facilities in various cities. Rail cars are leased from two entities. We lease portions of our office equipment. In addition to lease, we rent various facilities and equipment under temporary arrangements.

During 2008 we executed master lease agreements with Comerica Leasing Corporation, VFS Leasing Co., and Wells Fargo Equipment Finance, Inc. The market value of equipment leased under these agreements totaled $31,451 at the time of the lease. Certain of the transactions included the sale of hydraulic fracturing service equipment which was at least partially manufactured and assembled internally. Leasing companies purchased chassis equipment directly from the manufacturer and purchased additional assembly and modifications from us. Alternatively, leasing companies purchased completed hydraulic fracturing service equipment directly from us for the sale-leaseback transactions. Gain on sale of $1,790 was treated as deferred gain and is being amortized on a straight-line basis over the life of the lease. All leases under these agreements have five year terms, which consist of 60 monthly payments, and are treated as operating leases under ASC 840, Leases (“ASC 840”).

Total lease expense for 2008, 2009, and 2010 under operating leases consisted of the following:

Future minimum lease payments due under noncancellable operating leases as of December 31, 2010 consist of the following:

In the ordinary course of business, we are subject to various legal proceedings and claims. Management believes that costs associated with such legal matters, if any, will not have a material adverse effect on our financial condition, results of operations, or cash flows.

Much of the equipment we purchase requires long lead times in production. Due to this fact, at most points in time we have orders and commitments for such equipment. Some of these orders are being renewed on a revolving basis to achieve our goal of maintaining a future supply of essential equipment. All of these orders are cancelable upon written notice within time frames specified in the order (generally ninety days).

Transactions with related parties during 2008, 2009 and 2010 included facilities and office leasing, reimbursement of personnel and benefits costs, equipment purchases, construction contracting, repair parts and services, materials purchases, shared insurance policies, and some other minor transactions.

Transactions with related parties during 2008, 2009, and 2010 are summarized as follows:

During 2008, certain owners of our parent company advanced $13,500 to FTS under a preferred limited partner units agreement (“preferred units”). The preferred units were subsequently assigned to our parent. The preferred units did not provide for distribution, dividend or accumulation rights, and could be redeemed at the discretion of the holder. In October 2010, the preferred units were redeemed for $13,500.

We maintain a 401(k) Retirement Plan. Employees may contribute a portion of their salary, up to the limits established for an individual by the IRS, to a qualified 401(k) plan. As of December 31, 2009 and 2010 we did not provide any matching contributions.

We have recognized compensation expense based on the fair value of an ownership-based option grant provided to one of the members of our senior management team. The option entitles the holder to purchase a 2% equity interest in us, after giving effect to the exercise, as determined immediately prior to commencement of his employment. The option has an exercise price equal to the fair value of the underlying equity securities on the grant date, a ten-year term and vests in three equal annual installments beginning one year from the grant date. Our ownership-based compensation is measured on the grant date based on the fair value of the option grant and is recognized as an expense over the requisite service period, which is the vesting period, on a straight-line basis. The fair value of the ownership-based option grant is calculated through the use of an option pricing model.

A summary of the assumptions used in arriving at the fair value of the option grant is as follows:

The risk-free interest rate was based on the treasury yield rate with a maturity corresponding to the expected option life assumed at the grant date. Because we had not previously issued any options to our employees, and therefore had no historical forfeiture experience, we estimated the expected term of the option using the simplified method. The simplified method estimates the expected term of the option by calculating the mid-point between the vesting period end-date and the end of the contract term. Because there has not been a trading market for our equity securities, expected volatility of our stock price was based on historical and expected volatility rates of comparable publicly traded peers.

Changes to the underlying assumptions may have a significant impact on the resulting value of the option grants, which could have a material impact on our consolidated financial statements.

During the year ended December 31, 2010, we recognized $975 of ownership-based compensation expense.

Our primary business is providing high-pressure, high-volume hydraulic fracturing services to E&P companies. These services are part of the process of completing wells after they have been drilled (and determined to have found hydrocarbons).

In performing our services during 2008, 2009 and 2010, we derived approximately 52%, 53% and 38%, respectively, of our revenues from our three largest customers. Our three largest customers, as a percent of total revenue for the periods reported herein, impacted the financial statements as follows:

Effective January 1, 2009, the Company acquired an existing business which manufactures resin-coated sand. The acquisition was accounted for as a business combination in our consolidated balance sheets as of that date.

The other intangibles acquired were determined to have an indefinite useful life due to the ability to renew and or extend the underlying asset for an insignificant amount. Accordingly, the asset will be reviewed for impairment in connection with the review of recoverability of other long-lived assets. For the year ending December 31, 2010, no impairment charge was recorded.

This acquisition provided a competitive advantage because the existing company possessed an existing air permit for processing. To obtain a new permit for new plant construction, if one can be obtained at all, can take up to two years to acquire.

The acquired company’s operations were modified to produce resin-coated sand. No existing foundry customers were retained after the conversion. Sand was first delivered in January 2009. The company sells to FTS and FTS customers directly.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51, or SFAS No. 160” (“SFAS No. 160”) which is now incorporated into the ASC as ASC 810. ASC 810 establishes new accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. Among other items, ASC 810 requires that equity attributable to non-controlling interests be recognized in equity separate from that of the

Company’s and that consolidated net income now includes the results of operations attributable to non-controlling interests. The Company adopted ASC 810 on January 1, 2009 and it did not have a material impact on the Company’s consolidated financial statements.

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”) which is now incorporated into the ASC as ASC 810. ASC 810 changes the existing consolidation guidance applicable to a variable interest entity. Among other things, it requires a qualitative analysis to be performed in determining whether an enterprise is the primary beneficiary of a variable interest entity. ASC 810 is effective for interim and annual reporting periods that begin after November 15, 2009. The Company is currently evaluating the effect that ASC 810 will have on its consolidated financial statements.

The Company evaluated its December 31, 2010 consolidated financial statements for subsequent events through September 9, 2011, the date the financial statements were available to be issued.

We are not aware of any other subsequent events that would require recognition or disclosure in the consolidated financial statements, except as disclosed.

The accompanying notes are an integral part of these unaudited consolidated financial statements.

On May 6, 2011, the prior majority owners of Frac Tech Holdings, LLC, a Texas limited liability company (“FTH”), sold their interest in FTH to Frac Tech International, LLC, a newly-formed Delaware limited liability company (“FTI”), controlled by an investor group comprised of Maju Investments (Mauritius) Pte Ltd, an indirect wholly owned investment holding company of Temasek Holdings (Private) Limited, Senja Capital Ltd and other investors. This investor group funded the transaction with approximately $2.45 billion in cash and $1.50 billion principal amount of debt. In connection with the transaction (the “Acquisition Transaction”), Chesapeake Operating, Inc., a wholly owned subsidiary of Chesapeake Energy Corporation, contributed its minority interest in FTH 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. The Acquisition Transaction centralizes 100% ownership of FTH under our direct control.

In connection with the Acquisition Transaction, a new basis of accounting was established as of the acquisition date based on an allocation of the purchase consideration to the assets acquired and the liabilities assumed. See Note 3 for more information.

Due to the Acquisition Transaction, our consolidated financial statements and certain disclosures are presented in distinct periods to indicate the application of two bases of accounting. The term “successor” refers to FTI and its subsidiaries following the Acquisition Transaction. The term “predecessor” refers to FTH and its subsidiaries prior to the change in control on May 6, 2011.

These unaudited consolidated interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”), using policies that conform to US GAAP and have been consistently applied in all material respects. These financial statements should be read in conjunction with our predecessor’s audited consolidated financial statements and related notes for the year ended December 31, 2010. Even though our operations did not significantly change as a result of the Acquisition Transaction, certain of our costs were materially impacted due to the effects of acquisition accounting. Therefore, comparisons of our financial position and results of operations to those of our predecessor may not be meaningful due to the application of acquisition accounting related to the Acquisition Transaction. These financial statements and notes are representations of our management who is responsible for their integrity and objectivity. In the opinion of management, all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation have been included.

In these notes, references to “the Company,” “we,” “us,” and “our,” refer to FTI and its subsidiaries, as well as to FTH and its subsidiaries prior to the Acquisition Transaction, described below.

We provide hydraulic fracturing services to oil and natural gas producing companies through our wholly owned subsidiary FTH and its subsidiaries. We provide our services during well completion or during attempts to re-stimulate wells that have experienced production declines. At the end of June 2011, we were providing hydraulic fracturing services out of 11 districts: Artesia, New Mexico; Bryan, Texas; Elk City, Oklahoma; Longview, Texas; Minot, North Dakota; Odessa, Texas; Pleasanton, Texas; Shreveport, Louisiana; Vernal, Utah; Washington, Pennsylvania; and Williamsport, Pennsylvania. Within our consolidated group, we build hydraulic fracturing units and various other smaller pieces of equipment that are essential parts of the hydraulic fracturing

business. We produce from our own mines and processing plants the majority of the raw sand and resin-coated sand we use as proppants, and we transport most of the raw sand and other products to job sites by rail and truck using our distribution network. We also blend a portion of the chemicals we use in our operations at our chemical blending facility, located in Chickasha, Oklahoma, using our own proprietary formulas.

These consolidated financial statements include all wholly owned subsidiaries. In addition, we review our relationships with other entities to assess whether we are the primary beneficiary of a variable interest entity. If the determination is made that we are the primary beneficiary of a variable interest entity, then that entity is consolidated in accordance with US GAAP. All material intercompany balances are eliminated upon consolidation.

All highly liquid investments with an original maturity of three months or less when acquired are considered to be cash equivalents. We will occasionally hold cash deposits in financial institutions that exceed federally insured limits. We believe our risk of loss associated with these accounts to be remote.

Inventories consist of raw materials, work in process, proppants and supplies. Proppants include sand and chemicals which are used in providing hydraulic fracturing services and components and parts used in manufacturing and assembly of equipment used in our operations. Because we mine a portion of the sand used in our operations, the ending value of inventory contains certain extraction costs, which include labor, freight and

overhead. Inventories are carried at the lower of cost (or fair value at acquisition if acquired in the Acquisition Transaction) or market value determined on a first-in-first-out basis, except proppants and chemicals, which are determined on a weighted average cost basis. Raw materials are valued at cost, including freight, and work in process is valued at cost plus labor and overhead.

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 consist 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, other than land and sand reserves, on a straight-line basis over the estimated useful lives of the assets.

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. As a result of the Acquisition Transaction, we recognized a sand reserve asset of $371,700, which primarily relates to our extensive raw sand reserves in Voca, 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 (“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.

Other assets subject to amortization include software costs being amortized using the straight-line method over three years to seven years. Also included in other assets as of June 30, 2011 is $2,128 in deferred financing costs incurred in connection with the entry into our senior secured term loan in May 2011.

Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. Goodwill is not amortized, but is tested for impairment annually in the fourth fiscal quarter, 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, an impairment loss is measured as the difference between the implied fair value of the reporting unit’s goodwill and the carrying amount of goodwill.

We recorded indentified intangible assets at their estimated fair values as of the date of the Acquisition Transaction. Indefinite-lived intangible assets are not amortized, but are reviewed for impairment at least annually. The definite-lived intangible assets are amortized using the straight-line method over their economic lives.

Management is responsible for reviewing the carrying values of our long-lived assets, including fixed assets and intangibles 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.

Our cash and cash equivalents, accounts receivable, accounts payable and accrued expenses all approximate fair value due to the relative short term nature of the related account. Our outstanding indebtedness other than the senior notes bears interest at rates comparable to prevailing market terms, and therefore the outstanding balances approximate fair value. The senior notes were recorded at fair value in relation to the Acquisition Transaction on May 6, 2011, and therefore the June 30, 2011 carrying amount approximates fair value.

Promissory notes and other borrowings with original maturities of one year or less are classified as current liabilities.

Revenues are recognized as services are completed. With respect to our hydraulic fracturing services, we recognize revenue upon the completion of each fracturing stage. We typically complete one or more

fracturing stages per day during the course of a job. A stage is considered complete when we have met the specifications set forth in our contract with the customer for the number of hours our equipment is in use or the volume of sand used, or when the pressure exceeds the maximum specified in the contract for our equipment. Invoices typically include an equipment charge determined by applying a base rate for the amount of time the equipment is in operation, a mobilization charge (typically only for the first stage in a job) based on the distance equipment and products are transported to the job site, and product charges for proppant, chemicals and other products actually consumed during the course of providing our services. Revenues for services performed under dedicated service agreements are recognized as each stage is completed, as described above. To date, no additional revenues have been billed or recognized relating to shortfalls under the dedicated service agreements.

In November 2010, we granted an option to purchase a 2% equity interest in FTH to one of the members of our senior management team. We were recognizing the fair value of the option as an expense over the requisite service period, which is the vesting period, on a straight-line basis. The $19,140 grant date fair value of the option grant was calculated through the use of a Black-Scholes model, which requires subjective assumptions regarding future share price volatility and the expected life of each option grant.

A summary of the assumptions used in arriving at the fair value of the option grant is as follows:

Given the absence of any active market for our equity securities, the fair market value of the equity security underlying the option granted was determined by our board of managers, with input from our management. In determining such fair market value, for purposes of valuing the option granted in October 2010, our board of managers and management also considered a contemporaneous third-party valuation. Among other factors, such valuation reflected a discount for lack of liquidity, based on the fact that there has not been a trading market for our equity securities.

As of the date of the Acquisition Transaction, this option was fully vested and exercised. The fair value of the option has been fully expensed and will have no further impact on the results of operations. We had no outstanding ownership-based compensation grants as of June 30, 2011.

As required by the Securities and Exchange Commission financial reporting requirements, a pro forma income tax provision has been disclosed on the face of our statements of operations as if we were a taxable entity for federal and other states in which we operate. We have computed pro forma income tax expense using an effective rate of 37.9%, inclusive of our Texas margin tax, for both the predecessor and successor periods presented in the statements of operations.

The fair value of an asset or liability is based on the assumptions that market participants would use in pricing the asset or liability. Valuation techniques consistent with the market approach, income approach and/or cost approach are used to measure fair value. We follow a three-tiered fair value hierarchy when determining the inputs to valuation techniques. The fair value hierarchy prioritizes the inputs to valuation techniques into three broad levels in order to maximize the use of observable inputs and minimize the use of unobservable inputs. The levels of the fair value hierarchy are as follows:

The classification of assets and liabilities within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement in its entirety. As of December 31, 2010 and June 30, 2011, we had no financial assets or liabilities that were required to be measured at fair value on a recurring basis.

We obtained control of FTH on May 6, 2011 through a series of transactions whereby we purchased the majority equity interest of FTH in exchange for cash consideration totaling $3.6 billion, which included the issuance of a $1.5 billion senior secured term loan, due 2016 (the “senior secured term loan”) arranged by Bank of America, N.A., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Citigroup Global Markets, Inc. See Note 8 for further discussion of the senior secured term loan. Simultaneously, we received a contribution of the outstanding minority equity interest, which resulted in a total consideration value of approximately $5.0 billion being transferred in the Acquisition Transaction.

We recorded the Acquisition Transaction using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The values outlined below represent our best estimates of fair value as of the acquisition date. Certain estimated values, specifically those related to sand reserves and final working capital adjustments, are not yet finalized and are subject to change. We will finalize the amounts recognized 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 date of the Acquisition Transaction:

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques. Cash and cash equivalents, prepaid expenses, and accounts payable and accrued expenses were valued using a historical cost basis as this basis approximates fair value. Accounts receivable have been recorded on a historical net basis, which approximates the fair value. Inventory has been recorded on the estimated selling price less costs of disposal and a reasonable profit allowance for the effort to sell the inventory. Real property was valued based on comparable sales transactions. Personal property was valued using a combination of the cost and market approaches to estimate the fair value of the assets. Sand reserves were valued using the income approach for active sand mines and the market approach for raw land purchased for future mining activities.

Intangible assets—The following table summarizes the fair value estimates of the identifiable intangible assets and their weighted-average useful live:

The customer relationships, tradename, chemical blends and non-competition agreements have been valued using income approach methods which we determined were the most appropriate approach for the individual assets. Each of the intangible assets will be amortized over their estimated useful life, except the trade name, which has an indefinite life.

Goodwill—Our predecessor had recorded $3,212 of goodwill as of December 31, 2010. We recognized $2,706,637 in goodwill for the Acquisition Transaction, calculated as the excess of the consideration transferred over the net assets recognized. Goodwill represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized.

Liabilities assumed—We assumed the accounts payable, accrued liabilities and other current liabilities of FTH as part of the Acquisition Transaction. We determined that the historical cost basis of these liabilities approximated fair value as they comprise normal operating liabilities and will be settled at their historical cost basis within one year. We also assumed certain long-term debt as part of the acquisition. The fair value of the long-term debt was determined based on quoted market prices, which are considered Level 1 inputs.

The Acquisition Transaction constituted a change of control under the indenture governing our senior notes of our predecessor entity. As a result of the occurrence of the change of control, as required by the indenture, we made an offer to purchase any and all of our outstanding senior notes at a price equal to 101% of the outstanding principal amount of the senior notes plus accrued and unpaid interest to, but not including, the date of purchase. We commenced the offer to purchase on May 6, 2011. On June 7, 2011, we announced that $320 principal amount of the outstanding senior notes had been validly tendered and accepted for purchase in such tender offer.

In connection with the Acquisition Transaction, FTH’s prior majority owner purchased 100% of the outstanding equity interests in FTH’s subsidiary, Frac Tech Horizons, LLC (“Horizons”), for a purchase price of approximately $17.6 million. At the time of the closing, the assets of Horizons consisted of two airplanes and the outstanding equity of its wholly owned subsidiary, FTS Aero, LLC. Horizons had outstanding debt of approximately $11.8 million secured by one of such airplanes. The assets of FTS Aero, LLC consisted of one airplane. Upon the closing of that transaction, which occurred on the same date as the Acquisition Transaction, and in accordance with the indenture governing our senior notes, Horizons and FTS Aero, LLC, ceased to be guarantors of the senior notes under the indenture. We recorded this transaction as an equity adjustment with our members prior to the Acquisition Transaction.

Change of Control Payment, Acceleration of Management Option and Other Transaction Costs

The Acquisition Transaction constituted a change of control for purposes of certain employment agreements. Pursuant to the terms of these agreements, as a result of the Acquisition Transaction, certain options vested upon change of control and additional compensation payments became due. During the period from January 1 to May 5, 2011, we recognized $18,165 of ownership-based compensation expense, which included the impact of the accelerated vesting as well as $9.6 million in bonuses that became payable due to the change of control. Subsequent to May 5, 2011, we have also recognized $3.0 million of professional fees and other costs related to the Acquisition Transaction.

The following table presents the unaudited pro forma net revenues, operating income, and net income (based on the preliminary allocation of purchase price) as if the Acquisition Transaction had occurred on January 1, 2010 and assumes that there were no other changes in our operations. This pro forma information does not necessarily reflect the actual results that would have occurred had the Acquisition Transaction occurred on January 1, 2010, nor is it necessarily indicative of our future results of operations.

At December 31, 2010, our accounts receivable, net totaled $234,453 including $32,494 due from related parties and an allowance for bad debts of $6,717. At June 30, 2011, our accounts receivable, net totaled $309,144 including $76,389 due from related parties. Collection of receivables generally occurs between 30 and 60 days after the invoice date. We recorded bad debt expense of $895 during the six months ended June 30, 2010 and income of $1,636 related to the reversal of bad debt expense in the period from January 1, 2011 to May 5, 2011. We did not record any bad debt expense from May 6 to June 30, 2011.

The following table summarizes our fixed assets. Depreciation and depletion expense totaled $52,374, $52,494 and $32,809 in the six months ended June 30, 2010, the period from January 1 to May 5, 2011, and the period from May 6 to June 30, 2011, respectively.

The estimated useful lives of service equipment placed into service on or after October 1, 2010 range from 30 months to ten years. Service equipment used in our hydraulic fracturing services was previously depreciated over a period of ten years. Effective October 1, 2010, these items are being depreciated over a period of seven years. High-pressure iron, which is also included in service equipment, has an estimated useful life of 30 months. Also included in the balance of service equipment is the cost of manufacturing equipment which we utilize for the manufacture of our service equipment components. This manufacturing equipment has a useful life ranging from five to ten years.

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. Beginning October 1, 2010, we have charged the cost of fluid ends added as replacement parts to costs of revenues upon installation.

During the six months ended June 30, 2010, we recognized $5,651 in impairment of service equipment. The impairment was the result of increased utilization of our equipment in more demanding shale reservoirs that resulted in the replacement of equipment earlier than anticipated. No impairment charges have been recorded in 2011.

We capitalize an allocated amount of our borrowings for self-constructed assets and equipment during their construction period. We capitalized interest of $486, $1,760 and $771 in the six months ended June 30, 2010, the period from January 1 to May 5, 2011, and the period from May 6 to June 30, 2011, respectively.

We had $5,644 of indefinite-lived intangible assets as of December 31, 2010 which were not being amortized. Intangible assets other than goodwill were as follows as of June 30, 2011:

Amortization expense for other intangible assets was $59 and $16,325 for the period from January 1 to May 5, 2011 and the period from May 6 to June 30, 2011, respectively. The following presents estimated amortization of intangible assets through 2015:

Maturities for our debt including our senior notes and senior secured term loan as of June 30, 2011 are as follows:

Senior Secured Term Loan—In connection with the Acquisition Transaction, we entered into a $1.5 billion senior secured term loan and related security and other agreements with a syndicate of financial institutions as lenders and Bank of America, as administrative agent. Borrowings under the senior secured term loan, which matures on May 6, 2016, were used to finance the Acquisition Transaction.

Our obligations under the senior secured term loan are secured by a first priority security interest in all assets of FTI, including all of the equity interests in FTH.

The senior secured term loan bears interest at a rate per annum equal to LIBOR, plus an applicable margin based on our leverage. Interest is due and payable quarterly. We must repay the senior secured term loan in quarterly installments, in an amount of $3,750 beginning June 30, 2011, with the balance due upon final maturity on May 6, 2016. 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). Our senior secured term loan also requires that we make quarterly principal payments in an amount equal to the maximum amount we are permitted to distribute under the indenture governing our senior notes, less certain amounts.

The senior secured term loan contains a number of covenants that, among other things, restrict our ability and the ability of our subsidiaries to incur additional indebtedness; create liens on assets; make investments, loans or advances; engage in mergers or consolidations; sell assets; make acquisitions; pay dividends and make distributions or repurchase our and their equity interests; engage in certain transactions with affiliates; and make capital expenditures. These covenants are subject to a number of qualifications and exceptions.

In addition, our senior secured term loan requires us to maintain our interest coverage ratio of 2.50:1.00 and a maximum consolidated leverage ratio of 3.75:1.00 through December 30, 2011, decreasing by .25 each quarter thereafter until June 30, 2012 to 3.00:1.00. As of June 30, 2011, we were in compliance with all covenants.

Senior Notes—On November 12, 2010, Frac Tech Services, LLC (“FTS”) and Frac Tech Services, Inc., a wholly owned subsidiary of FTS, as co-issuers, completed a private offering of $550,000 aggregate principal amount of senior notes. The senior notes mature on November 15, 2018 and bear interest at 7.125% per annum, payable semi-annually in arrears on May 15 and November 15, which began May 15, 2011. The senior notes are unsecured and are guaranteed by FTS’s existing and future subsidiaries, subject to certain exceptions.

The senior notes are not entitled to any mandatory redemption or sinking fund. Prior to November 15, 2013, we may redeem up to 35% of the senior notes with proceeds of certain equity offerings at a redemption price of 107.125% of the principal amount plus accrued and unpaid interest. Prior to November 15, 2014, we may redeem some or all of the senior notes at a price equal to 100% of the principal amount plus a make-whole premium determined pursuant to a formula set forth in the Indenture governing the senior notes, plus accrued and unpaid interest. On or after November 15, 2014, we may redeem all or part of the senior notes at the following

prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on November 15 of the years indicated below:

The indenture governing the senior notes contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness or issue certain preferred equity; pay dividends on our equity or redeem equity or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. These covenants are subject to a number of qualifications and exceptions. As of June 30, 2011, we were in compliance with all covenants.

The indenture requires us to file with the Securities and Exchange Commission within 240 days after November 12, 2010 (or July 11, 2011) a registration statement for an offer to exchange the senior notes and related guarantees for registered notes and guarantees with identical terms, or in certain circumstances to file a shelf registration statement covering resales of the senior notes and guarantees. We have not filed such registration statement and therefore are required to pay additional interest. The rate of additional interest is 0.25% per annum for the first 90-day period immediately following the deadline to file the registration statement, and such rate will increase by an additional 0.25% per annum with respect to each subsequent 90-day period, up to a maximum additional interest rate of 1.0% per annum.

Revolving Credit Facility—On August 5, 2011, we entered into a $100 million revolving credit facility and related security and other agreements with a syndicate of financial institutions as lenders and Royal Bank of Canada, as administrative agent. The revolving credit facility includes a sublimit of $50 million for the issuance of letters of credit and allows for one or more swingline loans from Wells Fargo Bank, N.A. up to an aggregate amount of $20 million, provided certain conditions are met. The revolving credit facility will mature on August 5, 2016.

Loans under the revolving credit facility are available for FTS to borrow up to the lesser of (a) the $100 million commitment by the lenders (which may be reduced in certain circumstances) and (b) the borrowing base. The borrowing base is based on certain eligible inventory and accounts receivable of FTS and its wholly owned subsidiaries, with certain discounts applied, and will be redetermined from time to time.

Our obligations under the revolving credit facility are secured by a first-priority security interest in all of FTS’s and each of its wholly owned subsidiaries’ accounts receivable, inventory and proceeds thereof. None of the assets of Frac Tech Holdings, LLC or Frac Tech International, LLC are pledged as security as part of this financing.

The revolving credit facility is unconditionally guaranteed by each of FTS’s wholly owned domestic restricted subsidiaries.

Loans under the revolving credit facility will bear interest, at our option, at:

The applicable margin for the revolving credit facility is subject to change pursuant to a pricing grid based on availability under the revolving credit facility. In addition, the revolving credit facility provides for customary commitment fees and letter of credit fees.

The revolving credit facility contains a number of covenants that, among other things, restrict the ability of FTS and its restricted subsidiaries to incur additional indebtedness; create liens on assets; make investments, loans or advances; engage in mergers or consolidations; sell assets; make acquisitions; pay dividends and make distributions or repurchase their equity interests; and engage in certain transactions with affiliates. These covenants are subject to a number of qualifications and exceptions.

We lease certain administrative and sales offices and operational facilities in various cities. We lease rail cars and portions of our office equipment. In addition, we rent various facilities and equipment under temporary arrangements. Our lease expense was $7,215, $5,732 and $3,192 in the six months ended June 30, 2010, the period from January 1 to May 5, 2011, and the period from May 6 to June 30, 2011, respectively.

Prior to the Acquisition Transaction, transactions with related parties included charges for equipment, facilities and office leasing, reimbursement of personnel and benefits costs, equipment purchases, construction contracting, repair parts and services, materials purchases, and shared insurance policies, as well as provision of significant hydraulic fracturing services and some other minor transactions.

As a result of the Acquisition Transaction, the entities with which we engaged in many of the transactions reflected in the table below, other than the provision of hydraulic fracturing services, ceased to be related entities as of the closing date of the Acquisition Transaction, May 6, 2011. In subsequent periods, we anticipate that the only significant transactions with related entities will relate to our provision of hydraulic fracturing services to Chesapeake. The amounts shown in the table below as amounts we billed to related parties for frac services were billed to Chesapeake.

We maintain a 401(k) retirement plan. Employees may contribute a portion of their salary, up to the limits established for an individual by the IRS, to our 401(k) plan. As of December 31, 2010 we did not provide any matching contributions. Effective January 1, 2011, we began matching up to 4% of eligible employee contributions. We recorded expenses of $368 and $250 in the period from January 1 to May 5, 2011 and the period from May 6 to June 30, 2011, respectively, for matching contributions.

We derived approximately 42%, 37% and 33% of our revenues from our three largest customers in the six months ended June 30, 2010, the period from January 1 to May 5, 2011 and the period from May 6 to June 30, 2011, respectively.

In December 2010, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update requiring that step 2 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.

We have evaluated the June 30, 2011 unaudited consolidated financial statements for subsequent events through September 9, 2011, the date the financial statements were available to be issued.

Our senior secured term loan requires that we make quarterly principal payments in an amount equal to the maximum amount we are permitted to distribute under the indenture governing our Senior Notes, less certain amounts. Accordingly, we made a principal payment of $86.0 million on our senior secured term loan on August 19, 2011.

We are not aware of any other subsequent event that would require recognition or disclosure in the unaudited consolidated financial statements, except as disclosed.

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, which should be read in conjunction with these unaudited pro forma condensed consolidated financial statements.

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 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.

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

Once LIBOR exceeds the floor rate under our senior secured term loan, a 1/8th% variance in the interest rates that apply to our senior secured term loan borrowings would result in a change in pro forma interest expense by approximately $1,870 and $925 for the year ended December 31, 2010, and the six months ended June 30, 2011, respectively.

Through and including , 2011 (25 days after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts) payable by us in connection with the registration of the common stock offered hereby. The selling stockholder will be responsible for the underwriting discounts with respect to their shares sold in the offering, but we will pay all other expenses related to this offering. With the exception of the SEC registration fee, FINRA filing fee and NSYE listing fee, the amounts set forth below are estimates.

Our certificate of incorporation will provide that a director will not be liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (1) for any breach of the director’s duty of loyalty to the corporation or its stockholders, (2) for acts or omissions not in good faith or which involved intentional misconduct or a knowing violation of the law, (3) under section 174 of the DGCL for any unlawful payment of dividend or unlawful stock purchase or redemption or (4) for any transaction from which the director derived an improper personal benefit. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability provided for in our certificate of incorporation, will be limited to the fullest extent permitted by the amended DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s certificate of incorporation, bylaws, disinterested director vote, stockholder vote, agreement or otherwise.

Our certificate of incorporation and bylaws will contain indemnification rights for our directors and our officers. Specifically, our certificate of incorporation and bylaws will provide that we shall indemnify, and advance expenses to, our officers and directors to the fullest extent authorized by the DGCL.

We intend to enter into written indemnification agreements with our directors and officers. Under these proposed agreements, if an officer or director makes a claim of indemnification to us, either a majority of the independent directors or independent legal counsel selected by the independent directors must review the relevant facts and make a determination whether the officer or director has met the standards of conduct under Delaware law that would permit (under Delaware law) and require (under the indemnification agreement) us to indemnify the officer or director.

Further, we may maintain insurance on behalf of our officers, and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors, and on behalf of some of our employees for certain liabilities.

On November 12, 2010, Frac Tech Services, LLC and Frac Tech Services, Inc. completed a private offering of $550.0 million in principal amount of our 7.125% Senior Notes due 2018. The initial purchasers of the senior notes were Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC, Wells Fargo Securities, LLC, Jefferies & Company, Inc., Johnson Rice & Company, L.L.C., Comerica Securities, Inc. and Simmons & Company International. Pursuant to a Purchase Agreement between us and the initial purchasers, we sold the senior notes to the initial purchasers for $539.0 million (reflecting a discount of 2.0%), and the initial purchasers resold the senior notes at par to qualified institutional buyers under Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”) and to certain persons in offshore transactions in reliance on Regulation S under the Securities Act.

On May 6, 2011, in connection with the Acquisition Transaction, Frac Tech International, LLC issued an aggregate of 3,565,998,979.01 limited liability company units to an investor group comprised of Maju Investments (Mauritius) Pte Ltd, an indirect wholly owned investment holding company of Temasek Holdings (Private) Limited, Senja Capital Ltd and other investors. Chesapeake Operating, Inc., a wholly owned subsidiary of Chesapeake Energy Corporation, 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. The foregoing transactions were exempt from the registration requirements of the Securities Act pursuant to Section 4(2) thereof.

On August 15, 2011, Messrs. Rowland and Randle were each awarded 1,000,000 restricted units in Frac Tech International, LLC. Mr. Rowland’s restricted units vest in three equal installments on July 15, 2012 and 2013 and June 29, 2014. Mr. Randle’s restricted units vest in four equal installments on July 15, 2012 and 2013, and June 29, 2014 and 2015. In connection with our Conversion, these restricted units will convert into restricted shares of our common stock.

The foregoing issuances of securities by us and our predecessors did not involve any underwriters or public offerings and were exempt from the registration requirements pursuant to Section 4(2) of the Securities Act, and, in the case of the restricted units awarded to Messrs. Rowland and Randle, pursuant to Rule 701 under the Securities Act.

The Index to Exhibits, which follows the signature page to this registration statement on Form S-1 and is incorporated herein by reference, sets forth a list of those exhibits filed herewith.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement on Form S-1 to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Fort Worth, State of Texas, on September 9, 2011.

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Greg A. Lanham and Marcus C. Rowland, and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any or all amendments (including pre-effective and post-effective amendments) to this registration statement and any registration statement for the same offering filed pursuant to Rule 462 under the Securities Act of 1933, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement on Form S-1 has been signed by the following persons in the capacities indicated on September 9, 2011. This document may be executed by the signatories hereto on any number of counterparts, all of which constitute one and the same instrument.



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


	Per Share	Total
Public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to us	$	$
Proceeds, before expenses, to the selling stockholder	$	$


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
MANAGEMENT’S 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


	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	$


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		$


	Shares Purchased					Total Consideration				Average Price per Share
	Number		Percent			Amount	Percent			Average Price per Share
Existing stockholders		⁽¹⁾			%	$			%	$
New investors					%				%

Total				100	%	$		100	%	$


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


	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


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


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


	Percentage of Revenues
	Year Ended December 31,									Six Months Ended June 30, 2011
Customer	2008			2009			2010			Six Months Ended June 30, 2011
Chesapeake		17.1	%		10.6	%		8.2	%		15.9	%
Petrohawk Energy⁽¹⁾		3.3			20.6			16.6			10.3
XTO Energy⁽²⁾.		24.4			21.9			13.2			10.1
Range Resources Corporation		3.1			6.7			7.8			8.8
Antero Resources Corporation		10.2			*			*			*


Name	Age	Position
Marcus C. Rowland	58	Chief Executive Officer
James Coy Randle, Jr.	50	President and Chief Operating Officer
Chris Cummins	58	Senior Vice President of Proppants
Brad Holms	58	Senior Vice President—Global Business Development and Technology
Kevin McGlinch	41	Senior Vice President of Finance and Treasurer
Dan Patterson	43	Chief Accounting Officer, Senior Vice President of Accounting and Corporate Controller
Robert Pike	52	Senior Vice President of Sales
Charles Veazey	59	Senior Vice President of Operations
Justin Wilks	33	Senior Vice President of Logistics
William A. Hicks	57	General Counsel and Vice President
Domenic J. Dell’Osso, Jr.	35	Director
Greg A. Lanham	47	Director
Aubrey K. McClendon	52	Director
Goh Yong Siang	59	Director
Ong Tiong Sin	46	Director


Name and Principal Position	Salary		Bonus⁽¹⁾		Option Awards⁽²⁾		All Other Compensation⁽³⁾		Total
Marcus C. Rowland⁽⁴⁾	$	296,154	$	5,000,000	$	19,140,000	$	119	$	24,436,273
Chief Executive Officer

James Coy Randle, Jr.⁽⁵⁾	$	247,531	$	649,101		—	$	270	$	896,902
President and Chief Operating Officer

William A. Hicks	$	412,000	$	30,847		—	$	774	$	443,621
General Counsel and Vice President

Kevin McGlinch⁽⁶⁾	$	283,755	$	142,569		—	$	180	$	426,504
Senior Vice President of Finance and Treasurer

Charles B. Veazey	$	200,808	$	533,017		—	$	774	$	734,599
Senior Vice President of Operations


Name	Grant Date	Option Awards: Number of Securities Underlying Options		Exercise Price of Option Awards		Grant Date Fair Value of Option Awards
Marcus C. Rowland⁽¹⁾	11/01/2010		2,807	$	16,878	$	19,140,000


BofA Merrill Lynch		Goldman, Sachs & Co.


Citigroup		Credit Suisse


Named Executive Officer	Termination without Cause or for Good Reason		Change of Control Only		Change of Control and Termination without Cause or for Good Reason		Incapacity		Death
Marcus C. Rowland
Salary	$	800,000	$	—	$	1,600,000	$	400,000	$	800,000
Bonus		—		—		500,000		—		—

Total	$	800,000	$	—	$	2,100,000	$	400,000	$	800,000

James Coy Randle, Jr.
Salary	$	800,000	$	—	$	1,600,000	$	400,000	$	800,000
Bonus		—		—		500,000		—		—

Total	$	800,000	$		$	2,100,000	$	400,000	$	800,000

William A. Hicks
Salary	$	212,500	$	—	$	425,000	$	212,500	$	425,000
Bonus		—		—		127,500		—		—

Total	$	212,500	$	—	$	552,500	$	212,500	$	425,000

Kevin McGlinch
Salary	$	162,500	$	—	$	325,000	$	162,500	$	325,000
Bonus		—		—		130,000		—		—

Total	$	162,500	$	—	$	455,000	$	162,500	$	325,000

Charles B. Veazey
Salary	$	237,500	$	—	$	475,000	$	237,500	$	475,000
Bonus		—		—		213,750		—		—

Total	$	237,500	$	—	$	688,750	$	237,500	$	475,000


	Annual Base Salary		Annual Bonus Compensation
Mr. Hicks	$	425,000		30	%
Mr. McGlinch	$	325,000		40	%
Mr. Veazey	$	475,000		45	%


	Shares of Common Stock Beneficially Owned Prior to the Offering					Shares of Common Stock Being Offered		Shares of Common Stock Beneficially Owned After The Offering⁽¹⁾
Name of Beneficial Owner	Number		Percentage			Shares of Common Stock Being Offered		Number		Percentage
*5% Holders*
Maju Investments (Mauritius) Pte Ltd⁽²⁾				40.3	%		—				%
Chesapeake Operating, Inc.⁽³⁾				30.0	%						%
Senja Capital Ltd⁽⁴⁾				11.2	%		—				%
Cowboy Investment⁽⁵⁾				7.0	%		—				%
*Directors and Named Executive Officers*
Marcus C. Rowland⁽⁶⁾				1.1	%		—				%
James Coy Randle, Jr.⁽⁷⁾				*			—				*
William A. Hicks		—		—			—		—		—
Kevin McGlinch		—		—			—		—		—
Charles B. Veazey		—		—			—		—		—
Domenic J. Dell’Osso, Jr.⁽⁸⁾		—		—			—		—		—
Greg A. Lanham⁽⁹⁾		—		—			—		—		—
Aubrey K. McClendon⁽⁸⁾		—		—			—		—		—
Goh Yong Siang⁽⁹⁾		—		—			—		—		—
Ong Tiong Sin⁽¹⁰⁾		—		—			—		—		—
*All directors and executive officers as a group* (15 persons)				1.2	%


Year	Redemption Price
2014		103.563	%
2015		101.781	%
2016 and thereafter		100.000	%


Underwriter		Number of Shares
Merrill Lynch, Pierce, Fenner & Smith Incorporated.
Goldman, Sachs & Co.
Citigroup Global Markets Inc.
Credit Suisse Securities (USA) LLC

Total


	Page
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2009 and 2010		F-3
Consolidated Statements of Operations for the years ended December 31, 2008, 2009, and 2010		F-4
Consolidated Statements of Owners’ Equity for the years ended December 31, 2008, 2009, and 2010		F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2009, and 2010		F-6
Notes to Audited Consolidated Financial Statements		F-7


	Page
Unaudited Consolidated Financial Statements
Unaudited Consolidated Balance Sheets as of December 31, 2010 and June 30, 2011		F-21
Unaudited Consolidated Statements of Operations for the six months ended June 30, 2010, the period from January 1, 2011 through May 5, 2011, and the period from May 6, 2011 through June 30, 2011		F-22
Unaudited Consolidated Statements of Owners’ Equity for the period from January 1, 2011 through May 5, 2011 and the period from May 6, 2011 through June 30, 2011		F-23
Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2010, the period from January 1, 2011 through May 5, 2011, and the period from May 6, 2011 through June 30, 2011		F-24
Notes to Unaudited Consolidated Financial Statements		F-25

Unaudited Pro Forma Condensed Consolidated Financial Statements
Unaudited Pro Forma Condensed Consolidated Statement of Operations for the year ended December 31, 2010		F-43
Unaudited Pro Forma Condensed Consolidated Statement of Operations for the six months ended June 30, 2011		F-44
Unaudited Pro Forma Condensed Consolidated Balance Sheet as of June 30, 2011		F-45
Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements		F-46


	December 31,
	2009			2010
ASSETS
Current assets:
Cash and cash equivalents	$	26,039		$	291,781
Accounts receivable—trade, net		59,020			201,959
Inventories, net		55,137			83,733
Prepaid expenses		3,875			10,451
Amounts due from related parties, net		16,039			32,494
Other current assets		341			263

Total current assets		160,451			620,681
Fixed assets:
Property and equipment		767,356			972,714
Construction in process		6,491			43,175
Equipment advances		5,039			8,925
Accumulated depreciation		(208,868	)		(317,203	)

Total fixed assets, net		570,018			707,611
Goodwill		3,212			3,212
Other intangible assets		5,644			5,644
Other assets, net		1,216			14,780

Total assets	$	740,541		$	1,351,928

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	62,366		$	125,437
Amounts due to related parties		4,380			14,751
Accrued liabilities		27,289			76,772
Interest rate swaps		5,284			—
Loans from members		10,106			—
Revolving note payable		238,862			—
Current portion of long-term debt		29,107			12,925

Total current liabilities		377,394			229,885
Long-term liabilities:
Long-term notes, net of current portion		42,610			576,639
Interest rate swaps		425			—
Deferred gain		1,283			924

Total long-term liabilities		44,318			577,563

Commitments and Contingencies (Note 9)
Owners’ equity		318,829			544,480

Total liabilities and owners’ equity	$	740,541		$	1,351,928


Owners’ equity as of January 1, 2008	$	266,368
Issuance of preferred units		13,500
Contributions by owners		4,475
Net Income		43,359

Owners’ equity as of December 31, 2008		327,702
Contribution by owners		46,326
Distributions to owners		(14,960	)
Net Loss		(40,239	)

Owners’ equity as of December 31, 2009		318,829
Contribution by owners		100,000
Distributions to owners		(230,500	)
Redemption of preferred units		(13,500	)
Ownership-based compensation		975
Net Income		368,676

Owners’ equity as of December 31, 2010	$	544,480


	Estimated Useful Life (in years)		December 31,
	Estimated Useful Life (in years)		2009			2010
Land		N/A	$	28,021		$	43,573
Buildings and improvements		15-39		96,678			108,343
Service equipment		2.5-10		596,869			741,916
Vehicles and transportation equipment		5-20		34,908			63,645
Office equipment and other		3-7		10,880			15,237
Equipment construction in process		N/A		6,491			43,175
Equipment advances		N/A		5,039			8,925

Total cost of fixed assets				778,886			1,024,814
Accumulated depreciation				(208,868	)		(317,203	)

Net fixed assets			$	570,018		$	707,611


2011	$	12,925
2012		8,737
2013		4,744
2014		3,237
2015		904
Thereafter		559,017

Total	$	589,564


	Year Ended December 31,
2011	$	17,977
2012		15,875
2013		9,730
2014		3,510
2015		3,467
Thereafter		15,947

Total	$	66,506


Risk-free interest rate	1.23	%
Expected option life (in years)	6
Dividend yield	0	%
Expected volatility	55	%


Year Ended December 31,	Percentage of Revenue
2008		24.4	%	17.1	%	10.2	%
2009		21.9	%	20.6	%	10.6	%
2010		16.6	%	13.2	%	8.2	%


	Fair Value of Assets Acquired
Land	$	100
Building		350
Service equipment		11,756
Vehicles		50

		12,256
Other intangibles		5,244

Total purchase price	$	17,500


	Predecessor			Successor
	December 31, 2010			June 30, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	291,781		$	216,979
Accounts receivable—trade, net		201,959			232,755
Inventories, net		83,733			146,720
Prepaid expenses		10,451			8,672
Amounts due from related parties, net		32,494			76,389
Other current assets		263			37,776

Total current assets		620,681			719,291
Fixed assets:
Property and equipment		972,714			1,335,973
Construction in process		43,175			65,128
Equipment advances		8,925			9,041
Accumulated depreciation and depletion		(317,203	)		(31,915	)

Total fixed assets, net		707,611			1,378,227
Goodwill		3,212			2,706,637
Other intangible assets		5,644			1,060,515
Other assets, net		14,780			4,978

Total assets	$	1,351,928		$	5,869,648

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	125,437		$	165,271
Amounts due to related parties		14,751			—
Accrued liabilities		76,772			57,705
Other current liabilities		—			9,729
Current portion of long-term debt		12,925			24,865

Total current liabilities		229,885			257,570
Long-term liabilities:
Long-term notes, net of current portion		576,639			2,038,241
Deferred gain		924			—

Total long-term liabilities		577,563			2,038,241

Commitments and contingencies (Note 10)
Owners’ equity		544,480			3,573,837

Total liabilities and owners’ equity	$	1,351,928		$	5,869,648


	Predecessor						Successor
	Six Months Ended June 30, 2010			Period from January 1 to May 5, 2011			Period from May 6 to June 30, 2011
Revenues:
Revenues from third parties	$	417,984		$	620,600		$	303,907
Revenues from related parties		33,890			108,765			63,090

Total revenues		451,874			729,365			366,997

Operating costs:
Costs of revenues, excluding depreciation, depletion and amortization		245,482			365,480			245,763
Selling and administrative costs		49,091			88,695			30,001
Depreciation, depletion and amortization		52,959			52,553			49,134

Total operating costs		347,532			506,728			324,898

Income from operations		104,342			222,637			42,099
Other income (expense):
Interest income		121			82			125
Interest expense		(11,650	)		(14,017	)		(22,954	)
Other		(66	)		(1,347	)		296

Net other expense		(11,595	)		(15,282	)		(22,533	)

Income before income taxes		92,747			207,355			19,566
Provision for income taxes		1,685			2,051			730

Net income	$	91,062		$	205,304		$	18,836

Pro forma information:
Net income as reported	$	91,062		$	205,304		$	18,836
Pro forma adjustment for income tax expense		34,217			76,512			6,841

Pro forma net income	$	56,845		$	128,792		$	11,995

Basic and diluted net income per share
Weighted average number of shares outstanding:
Basic
Diluted


Predecessor:
Owners’ equity as of December 31, 2010	$	544,480
Ownership-based compensation		18,165
Distributions to members		(99,291	)
Net income		205,304

Owners’ equity as of May 5, 2011	$	668,658

Successor:
Opening balance	$	3,566,124
Distributions to members		(11,123	)
Net income		18,836

Owners’ equity as of June 30, 2011	$	3,573,837


	Predecessor						Successor
	Six Months Ended June 30, 2010			Period from January 1 to May 5, 2011			Period from May 6 to June 30, 2011
Cash flows from operating activities:
Net income	$	91,062		$	205,304		$	18,836
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation, depletion and amortization		52,959			52,553			49,134
Impairment of service equipment		5,651			—			—
(Gain)/loss on sale of assets		338			2,244			(541	)
Amortization of deferred financing costs, debt premium, and original issue discount		—			578			2,013
Amortization of deferred gain		(180	)		(125	)		—
Bad debts		895			(1,636	)		—
Ownership-based compensation		—			18,165			—
Changes in fair value of interest rate swaps		(3,187	)		—			—
Changes in operating assets and liabilities:
Accounts receivable		(82,786	)		(80,775	)		7,802
Inventories		(2,976	)		(59,517	)		55,012
Prepaid expenses		(3,009	)		2,489			(666	)
Other assets		(728	)		560			(1,971	)
Accounts payable		6,566			36,148			(20,457	)
Accrued liabilities		10,877			29,991			(38,902	)
Other current liabilities		—			—			3,282
Customer prepayments		(5	)		—			—

Net cash provided by operating activities		75,477			205,979			73,542

Cash flows from investing activities:
Purchase of property and equipment		(47,689	)		(188,880	)		(90,236	)
Acquisition of Frac Tech Holdings, LLC, net of cash acquired		—			—			(3,660,190	)
Proceeds from disposition of assets		1,528			21,110			654

Net cash used in investing activities		(46,161	)		(167,770	)		(3,749,772	)

Cash flows from financing activities:
Proceeds from revolving credit facility		46,716			—			—
Repayment of revolving credit facility		(175,578	)		—			—
Proceeds from long-term debt		3,773			2,357			1,454,518
Repayment of long-term debt		(11,559	)		(5,427	)		(5,827	)
Contributions from members		100,000			—			2,227,784
Distributions to members		—			(96,356	)		(11,123	)
Loans from members		4,984			—			—
Deferred financing costs		—			—			(3,693	)
Net change in receivables from related parties		884			986			—

Net cash provided by (used in) financing activities		(30,780	)		(98,440	)		3,661,659

Net decrease in cash		(1,464	)		(60,231	)		(14,571	)
Cash and cash equivalents, beginning of period		26,039			291,781			231,550

Cash and cash equivalents, end of period	$	24,575		$	231,550		$	216,979

Non-cash contribution of members’ units	$	—		$	—		$	1,336,986


Cash and cash equivalents	$	233,071
Accounts receivable		294,324
Inventories		201,730
Prepaid expenses and other current assets		45,453
Fixed assets		1,321,913
Goodwill		2,706,637
Other intangible assets		1,076,800
Other non-current assets		1,213

Total assets	$	5,881,141

Accounts payable	$	177,340
Accrued liabilities and other current liabilities		106,965
Debt		618,543

Total liabilities	$	902,848