Index to Financial Statements

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. x

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

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):

CALCULATION OF REGISTRATION FEE



Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)	Amount of Registration Fee
Common stock, par value $0.01 per share, underlying warrants	$ 2,470	$0.29

(1)	Estimated in accordance with Rule 457(g), calculated on the basis of the warrant exercise price, $0.01 per share.

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

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 any offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, dated June 13, 2012

PRELIMINARY PROSPECTUS

LOGO

Green Field Energy Services, Inc.

247,058 Shares of Common Stock

This prospectus relates to the resale of 247,058 shares of common stock, $0.01 par value per share (“common stock”), to be offered by the shareholders identified under the “Selling Shareholders” section of this prospectus exercise of outstanding warrants. We initially issued the warrants as part of 250,000 units (the “units”), each consisting of $1,000 principal amount of our 13% senior secured notes due 2016 (the “13% notes”) and a warrant to purchase 0.988235 shares of common stock (collectively, the “warrants”).

We will not receive any proceeds from the sale of common stock by the selling shareholders. Holders of our common stock are entitled to one vote for each share of common stock held.

Our common stock is not listed for trading on any national securities exchange. The selling shareholders may sell shares of common stock from time to time in privately negotiated transactions or on the principal market on which our common stock may be traded in the future.

Investing in our common stock involves risks. You should carefully consider the “Risk Factors” beginning on page 4 of this prospectus.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ADEQUACY OR ACCURACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

YOU SHOULD READ THIS ENTIRE DOCUMENT AND THE ACCOMPANYING LETTER OF TRANSMITTAL AND RELATED DOCUMENTS AND ANY AMENDMENTS OR SUPPLEMENTS CAREFULLY BEFORE MAKING A DECISION WHETHER TO PURCHASE OUR COMMON STOCK.

The date of this prospectus is , 2012

Table of Contents


About this Prospectus			ii
Cautionary Statements Regarding Forward-Looking Statements			iii
Prospectus Summary			1
Risk Factors			4
Use of Proceeds			16
Dividend Policy			17
Management’s Discussion and Analysis of Financial Condition and Results of Operations			18
Business			34
Management			47
Beneficial Ownership			53
Selling Shareholders			54
Determination of Offering Price and Plan of Distribution			55
Certain Relationships and Related Person Transactions			56
Description of Common Stock			60
Shares Eligible for Future Sale			62
Material U.S. Federal Income Tax Considerations			63
Legal Matters			67
Experts			67
Where You Can Find More Information			67
Index to Financial Statements			F-1

Industry and Market Data

We have obtained the market and competitive position data used throughout this prospectus from our own research, surveys or studies conducted by third parties and industry or general publications. Industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data, and we do not make any representation as to the accuracy of such information. Similarly, we believe our internal research is reliable, but it has not been verified by any independent sources.

Trade Names and Trademarks

This prospectus may also include trade names and trademarks of other companies. Our use or display of other parties’ trade names, trademarks or products is not intended to, and does not imply a relationship with, or endorsement or sponsorship of us by, the respective owners of such trade names, trademarks or products.

About This Prospectus

We have filed with the Securities and Exchange Commission (the “SEC”) a registration statement (“Registration Statement”) on Form S-1 under the Securities Act of 1933, as amended (the “Securities Act”), with respect to the common stock. This prospectus, which is a part of the Registration Statement, omits certain information included in the Registration Statement and in its exhibits. For further information relating to us and our common stock, we refer you to the Registration Statement and its exhibits, from which this prospectus incorporates important business and financial information about the Company that is not included in or delivered herewith. You may read and copy the Registration Statement, including its exhibits, at the SEC’s Public Reading Room located at 450 Fifth Street, N.W., Washington D.C. 20549. You may obtain information on the operation of the Public Reading Room by calling the SEC at 1-800-SEC-0300. The SEC also maintains a Web site (www.sec.gov) that contains reports, proxy and information statements and other information regarding registrants like us who file electronically with the SEC.

We are not currently subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Following effectiveness of the registration statement of which this prospectus is a part, we will file annual, quarterly and current reports and other information with the SEC in accordance with the Exchange Act. You may read and copy any document we file with the SEC at the SEC’s address set forth above.

You should rely only on the information contained in this prospectus. We have not authorized any person to provide you with any information or represent anything not contained in this prospectus, and, if given or made, any such other information or representation should not be relied upon as having been authorized by us. We are not making an offer to sell our common stock in any jurisdiction where an offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus. We will disclose any material changes in our affairs in an amendment to this prospectus or a prospectus supplement.

We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation.

Cautionary Statement Regarding Forward-Looking Statements

This prospectus contains “forward-looking statements” within the meaning of Section 27A of the Securities Act. These statements involve known and unknown risks, uncertainties and other important factors that may cause our actual results, performance or achievements to be materially different from any future results, performances or achievements expressed or implied by the forward-looking statements. Forward-looking statements may include, but are not limited to, projections of revenue, statements relating to our future financial performance, the growth of the market for our services, expansion plans and opportunities and statements regarding our plans, strategies and objectives for future operations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “potential” or “continue,” the negative of such terms or other comparable terminology.

Forward-looking statements reflect our current views about future events, are based on assumptions, and are subject to known and unknown risks and uncertainties. Many important factors could cause actual results or achievements to differ materially from any future results or achievements expressed in or implied by our forward-looking statements, including the factors listed below. Many of the factors that will determine future events or achievements are beyond our ability to control or predict. Certain of these are important factors that could cause actual results or achievements to differ materially from the results or achievements reflected in our forward-looking statements, including, but not limited to:

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general economic conditions and conditions affecting the industries we serve;

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the level of oil and natural gas exploration, development and production in the U.S.;

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our future financial and operating performance and results;

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our business strategy and budgets;

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changes in technology;

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our financial strategy;

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amount, nature and timing of our capital expenditures;

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changes in competition and government regulations;

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our operating costs and other expenses;

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our cash flow and anticipated liquidity; and

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our plans, forecasts, objectives, expectations and intentions.

These forward-looking statements reflect our views and assumptions only as of the date such forward-looking statements are made. You should not place undue reliance on forward-looking statements. Except as required by law, we assume no responsibility for updating any forward-looking statements nor do we intend to do so. Our actual results, performance or achievements could differ materially from the results expressed in, or implied by, these forward-looking statements. The risks included in this section are not exhaustive. Additional factors that could cause actual results to differ materially from those described in the forward-looking statements are set forth under the section titled “Risk Factors.”

iii

Prospectus Summary

The following summary highlights information contained elsewhere in this prospectus and does not contain all of the information you should consider before investing in our common stock. You should read carefully the rest of this prospectus and should consider, among other things, the matters set forth under the sections titled “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our combined financial statements and related notes to those statements and other financial data included elsewhere in this prospectus. Some of the statements in the following summary are forward-looking statements. See the section titled “Cautionary Statement Regarding Forward-Looking Statements.” Unless the context requires otherwise, references in this prospectus to the “Company,” “we,” “us,” “our” or “ours” refer to Green Field Energy Services, Inc., together with its subsidiaries and predecessor entities.

Company Overview

Formed in 1969, we are an independent oilfield services company that provides a wide range of services to oil and natural gas drilling and production companies to help develop and enhance the production of hydrocarbons. Our services include hydraulic fracturing, cementing, coiled tubing, pressure pumping, acidizing and other pumping services. We also produce our own TFPs (as defined below).

We began providing hydraulic fracturing services in December 2010. Our hydraulic fracturing operations utilize turbine-powered hydraulic fracturing pumping equipment that we believe provides several advantages over the diesel-powered pumping equipment generally utilized in the industry. These advantages include lower emissions, a smaller operating footprint, lower operating costs and greater fuel flexibility, including the ability to operate on natural gas. “HP” as used in this prospectus means the maximum horsepower rating on the applicable pump(s).

Each of our turbine-powered hydraulic fracturing units consists primarily of a high pressure hydraulic pump, a turbine engine, a gear box, electrical and hydraulic assemblies, and skids (collectively, a “TFP”) and various hoses, valves, tanks and other supporting equipment that are typically mounted to 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 hydraulic fracturing “spread” and we refer to all of our spreads together as our hydraulic fracturing “fleet.”

As of June 8, 2012, our fleet has 108,000 HP of turbine-powered high pressure pumping capacity and commitments of $68 million for the purchase of additional equipment. With our current customer commitments and in light of current market conditions, we intend to expend only an approximate $33.2 million for the remainder of 2012 to acquire hydraulic fracturing and well services equipment to add another 46,000 HP of turbine-powered high pressure capacity to our fleet and six coiled tubing units. We now plan to have a fleet with approximately 154,000 HP of turbine-powered high pressure capacity. We do not anticipate adding more horsepower without additional firm customer commitments in the future and we may also consider reconfiguring or selling some portion of the earlier assembled units in the fleet based on customer commitments and our evaluation of the market over the near term.

As of June 8, 2012, we had approximately 117,000 HP of high pressure pumping capacity in our fleet, of which 108,000 HP was turbine-powered.

Corporate Reorganization

Conversion

The Company was formerly a Louisiana limited liability company under the name Hub City Industries, L.L.C. In September 2011, we changed our name to Green Field Energy Services, LLC, and in October 2011, we converted into a Delaware corporation.

Equity Redemptions and Repurchases

In May 2011, we entered into agreements with certain of our members to repurchase all of their equity interests in us for cash. These redemption agreements required upfront payments to be made to certain parties as well as earnout payments to be made to all parties over time based on the gross revenues of our hydraulic fracturing services. As of September 30, 2011, payment of the repurchase obligations with respect to the equity interests of two members, Moody Moreno & Rucks, L.L.C. (“MMR”) and Egle Ventures, L.L.C. (“Egle”), remained outstanding and were classified as debt on our balance sheet as of that date. On October 13, 2011, the Company and MMR, an entity in which our Chief Executive Officer indirectly holds a 40% ownership interest, agreed to rescind the redemption agreement applicable to the equity interests previously held by MMR, thereby eliminating the approximate associated $27.9 million debt obligation reflected on the Company’s balance sheet. On October 14, 2011, the Company paid $0.7 million of its outstanding obligation to Egle and MOR MGH Holdings, L.L.C. (“MMH”) assumed the remainder of that obligation, in the amount of $3.0 million, thereby eliminating the associated approximate $3.7 million debt obligation reflected on the Company’s balance sheet. Egle is owned by our prior chief executive officer, John Eglé. Please see the section titled “Certain Relationships and Related Person Transactions.” Following these redemptions and repurchases, as of October 17, 2011, MMH owned, on a undiluted basis, 88.9% of our common stock and MMR owned, on an undiluted basis, the remaining 11.1%. This series of transactions resulted in a change of control of the Company in May 2011 which requires a new basis of accounting be established as of the date of the change in control. Due to this, the consolidated financial statements and certain disclosures are presented in distinct periods to indicate the application of the two bases of accounting. The term “Predecessor” refers to the Company prior to the change in control and the term “Successor” refers to the Company following the change in control.

Stock Split

In November 2011 we amended our certificate of incorporation to, among other things, effect a stock split on a 1,400 for 1 basis. The stock split was effected simultaneously for all our then-issued and outstanding common stock and the exchange ratio was the same for each share of issued and outstanding common stock. The stock split affected all of our stockholders uniformly and did not affect any stockholder’s percentage ownership interest in us. Shares of common stock issued pursuant to the stock split are fully paid and nonassessable.

Recent Developments

Senior Credit Facility. In April 2012, we entered into an amendment to the Shell agreement, to add a senior credit facility and to amend provisions providing security for amounts advanced under such credit facility. The credit facility provides for advances of $30 million. The advances bear no interest and are to be repaid in monthly payments. Please see the section titled “Business—Shell Agreement.”

In connection with our senior credit facility, we entered into an intercreditor agreement with Shell, Hub City Tools, Inc. and Wilmington Trust, National Association. The terms of the intercreditor agreement are consistent with the intercreditor agreement attached as an exhibit to our indenture.

General Corporate Information

Green Field Energy Services, Inc. is incorporated under Delaware law. Our principal executive offices are located at 4023 Ambassador Caffery Parkway, Suite 200, Lafayette, LA 70503, and our telephone number at that address is (337) 706-1700. Our website address is http://gfes.com; however, information contained on our website is not incorporated by reference into this prospectus, and you should not consider the information contained on our website to be part of this prospectus.

Summary of the Offering

Issuer

Green Field Energy Services, Inc.

Common Stock Being Offered by the Selling Shareholders

247,058 shares of common stock issuable upon exercise of the warrants.

Shares of Common Stock Outstanding Prior to this Offering

1,400,000

Shares of Common Stock Outstanding After this Offering

1,647,058

Use of Proceeds

All of the common stock offered hereby will be sold by the selling shareholders. We will not receive any proceeds from the sale of these shares. See “Use of Proceeds.”

Offering Price

All or some of the shares offered hereby may be sold from time to time in amounts and or terms to be determined by the selling stockholders at the time of sale.

Voting Rights

Holders of common stock are entitled to one vote for each share of common stock held.

Dividend Policy

Holders of common stock have the right to receive dividends when and as dividends are declared by our Board of Directors. We have not paid dividends on our common stock and do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our senior credit facility and the indenture governing our 13% notes restrict our ability to pay dividends on our common stock.

Liquidation Rights

Upon any liquidation, dissolution or winding up of the affairs of the Company, whether voluntary or involuntary, any assets remaining after satisfaction of the rights of creditors and the rights of any holders of preferred stock will be distributed to the holders of common stock.

Trading Market

There is currently no established public market for trading of the shares of our common stock being offered hereby.

Risk Factors

You should carefully consider the information set forth in this prospects and, in particular, the specific factors set forth in the “Risk Factors” section before deciding whether to purchase shares of our common stock.

For more information about the common stock, see “Description of Common Stock.”

Risk Factors

You should carefully consider all of the information set forth in this prospectus and, in particular, you should refer to the section captioned “Risk Factors” for an explanation of certain risks related to investing in the common stock.

Risk Factors

You should carefully consider the risks described below, as well as the other information contained in this prospectus and our other filings with the SEC, before making an investment decision in our common stock. The risks described below are not the only ones that we face. Additional risks not presently known to us or that we currently deem immaterial may also impair our business operations. The actual occurrence of any of these risks could materially adversely affect our business, financial condition and results of operations. In that case, the value of the Securities could decline substantially, and you may lose part or all of your investment.

Risks Related to Investing in our Common Stock

There may be no public market for the common stock being offered, which could significantly impair the liquidity of the common stock.

There has been no public market for any of the common stock. As of the date of this prospectus, all of our common stock is privately held. Our common stock is not listed on any exchange and we do not intend to apply for any listing. We cannot assure you as to:

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whether any public market will develop for the common stock;

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the liquidity of any such market that may develop;

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your ability to sell your common stock; or

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the price at which you would be able to sell your common stock.

The initial purchaser of the warrants from which these shares of common stock are issuable upon exercise has advised us that it intends to make a market in the common stock. The initial purchaser is not obligated, however, to make a market in the common stock, and they may discontinue any such market-making at any time at their sole discretion. Accordingly, we cannot assure you as to the development or liquidity of any market for our common stock.

There may be dilution of the value of our common stock when the warrants become exercised.

On November 15, 2011, we issued warrants to purchase common stock representing 17.6% of our outstanding common stock on a fully diluted basis as of such date (assuming exercise of all such warrants) as part of an issuance of investment units consisting of (a) $1,000 principal amount of our 13% senior secured notes due 2016 and (b) one warrant. Because common stock is issuable upon exercise of the warrants, and in particular because the warrants are initially exercisable for $0.01 per share of common stock, there may be a dilutive effect on the value of our common stock when the warrants are exercised.

We do not intend to pay dividends on the common stock in the foreseeable future.

We have not paid dividends on our common stock and do not anticipate paying any cash dividends on the common stock in the foreseeable future. In addition, the terms of our senior credit facility and the indenture governing the notes restrict our ability to pay dividends on the common stock.

As a result of this offering, we will become subject to financial reporting and other requirements for which our accounting, internal audit and other management systems and resources may not be adequately prepared.

This offering will subject us to reporting and other obligations under the Securities Exchange Act of 1934, as amended, including the requirements of Section 404 of the Sarbanes-Oxley Act. Section 404 will require us to conduct an annual management assessment of the effectiveness of our internal controls over financial reporting and to obtain a report by our independent auditors addressing these assessments. These reporting and other obligations will place significant demands on our management, administrative, operational, internal audit and

accounting resources. We also expect these regulations to increase our legal and financial compliance costs, make it more difficult to attract and retain qualified officers and members of our board of directors and make some activities more difficult, time consuming and costly. We are presently upgrading our systems, implementing financial and management controls, reporting systems and procedures and implementing an internal audit function; we also have hired additional accounting, internal audit and finance staff. If we are unable to accomplish these objectives in a timely and effective fashion, our ability to comply with our financial reporting requirements and other rules that apply to reporting companies could be impaired. Any failure to maintain effective internal controls could have a material adverse effect on our business, operating results and stock price. Moreover, effective internal control is necessary for us to provide reliable financial reports and prevent fraud. If we cannot provide reliable financial reports or prevent fraud, we may not be able to manage our business as effectively as we would if an effective control environment existed, and our business and reputation with investors may be harmed.

Risks Relating to Our Business

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

We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas in the United States. If these expenditures decline, our business may suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which our management has no control, such as:

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

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

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the supply of and demand for hydraulic fracturing and other well service equipment in the United States;

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public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;

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the expected rates of decline of current oil and natural gas production;

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

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regulation of drilling activity;

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the discovery rates of new oil and natural gas reserves;

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available pipeline and other transportation capacity;

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

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political instability in oil and natural gas producing countries;

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domestic and worldwide economic conditions;

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technical advances affecting energy consumption;

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the price and availability of alternative fuels; and

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merger and divestiture activity among oil and natural gas producers.

The level of activity in the oil and natural gas E&P industry in the United States is volatile. In 2009, our industry experienced an unprecedented decline in drilling activity in the United States as rig counts dropped by approximately 57% from 2008 highs. Unexpected material declines in oil and natural gas prices, or drilling or

completion activity in the southern United States oil and natural gas shale regions, could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, a decrease in the development rate of oil and natural gas reserves in our market areas may also have an adverse impact on our business, even in an environment of stronger oil and natural gas prices.

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

In 2009, significant declines in prices for oil and natural gas, together with adverse changes in the capital and credit markets, caused many E&P companies to reduce capital budgets and drilling activity. This trend resulted in a significant decline in demand for our industry’s services, had a material negative impact on the prices companies were able to charge their customers, and adversely affected equipment utilization and results of operations. Future fluctuations in such prices may result in a decrease in expenditure levels of oil and natural gas companies and drilling contractors which in turn may adversely affect us.

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

Currently, the demand for hydraulic fracturing services exceeds the availability of fracturing equipment and crews across the industry and in our target markets in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional, as opposed to conventional, oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages has further amplified this equipment and crew shortage. As a result, we and our competitors have ordered additional fracturing equipment to meet existing and projected long-term demand. However, the recent declines in natural gas prices has resulted in reduced drilling activity in natural gas shale plays which could result in a decrease in demand for hydraulic fracturing services. If demand for fracturing services decreases or the supply of fracturing equipment and crews increases, then the increase in supply relative to demand may result in lower prices and utilization of our services and could adversely affect our business and results of operations.

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

As of June 8, 2012, we had approximately 117,000 HP of high pressure pumping capacity in our fleet, of which 108,000 HP was turbine-powered. We expect to continue to increase the high pressure pumping capacity of our fleet through additional equipment that will provide us with an aggregate turbine-powered high pressure pumping capacity of 154,000 HP.

The delivery of the pumps or any other fracturing equipment we have ordered or may order in the future could be materially delayed or not delivered at all. Three equipment suppliers are constructing our hydraulic fracturing pumps to be utilized for our hydraulic fracturing units. These pumps will then be delivered to Dynamic Industries, Inc. (“Dynamic”) for mounting onto the pump skids, and then to TPT, for the addition of the turbines and completion of the TFPs. Please see the section titled “Certain Relationships and Related Person Transactions—Joint Venture” for additional information. The overall number of hydraulic fracturing equipment suppliers in the industry is limited, and there is high demand for such equipment, which may increase the risk of delay or failure to deliver and limit our ability to find alternative suppliers. Any material delay or failure to deliver new equipment could defer or substantially reduce our revenue from the deployment of this equipment for our fracturing units.

If we cause disruptions to our customers’ businesses or provide inadequate service, particularly by failing to meet our delivery deadlines in the Shell agreement, our customers may have claims for damages against us, which could cause us to lose customers, have a negative effect on our reputation and adversely affect our results of operations.

If we fail to provide services under our contracts with our customers, like our contract with Shell, we may disrupt such customers’ business, which could result in a reduction in our revenues or a claim for substantial damages against us. In addition, a failure or inability to meet a contractual requirement could seriously damage our reputation and affect our ability to attract new business. Any significant failure of our equipment, or any major disruption in our acquisition of equipment from TPT or our other vendors, could impede our ability to provide services to our customers, have a negative impact on our reputation, cause us to lose customers and adversely affect our results of operations. For example, under our Shell agreement, if we fail to deliver hydraulic fracturing units by the scheduled delivery dates in 2012, Shell may terminate the agreement for cause, and we would be required to pay Shell $10 million in liquidated damages within 90 days of the date such termination is effective. The successful assertion of one or more large claims against us in amounts greater than those covered by our current insurance policies could materially adversely affect our business, financial condition and results of operations. Even if such assertions against us are unsuccessful, we may incur reputational harm and substantial legal fees.

Delays in deliveries of key raw materials or increases in the cost of key raw materials could harm our business, results of operations and financial condition.

We have established relationships with a limited number of suppliers of our raw materials. Should any of our current suppliers be unable to provide the necessary raw materials (such as proppant or chemicals) or otherwise fail to deliver such raw materials in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, financial condition, results of operations and cash flows. Our industry has faced sporadic proppant shortages associated with pressure pumping operations requiring work stoppages, which adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of raw materials, including proppants. In connection with the newly leased sand mines, we have entered into a contract with Alliance Consulting Group, an affiliate, to build and operate a Wet and Dry facility to process and transport sand from our mines. However, there can be no assurance that such equipment will be delivered as anticipated and any such delays or unavailability may adversely impact our ability to produce the estimated quantity of sand at each mine. Failure to achieve our production estimates in a timely manner could have a material adverse effect on any or all of our future cash flows, profitability, results of operations and financial condition.

Inaccuracies in our estimates of sand reserves could result in lower than expected revenues and higher than expected costs.

We base our sand reserves estimates on engineering, economic and geological data assembled and analyzed by our staff and on the data and conclusions in the subsurface sand report prepared by Terracon. These estimates are also based on the expected cost of production and projected sale prices. There are numerous factors and assumptions inherent in estimating quantities and qualities of sand reserves and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable sand reserves necessarily depend upon a number of variable factors and assumptions, all of which may vary considerably from actual results.

For these reasons, estimates of the quantities and qualities of the economically recoverable sand attributable to our sand mines, classifications of sand reserves based on risk of recovery, estimated cost of production and estimates of net cash flows expected from particular reserves as prepared by different engineers or by the same engineers at different times may vary materially due to changes in the above factors and assumptions. Actual production from identified sand deposit areas or properties and revenues and expenditures associated with our mining operations may vary materially from estimates. Accordingly, these estimates may not reflect our actual sand reserves. Any inaccuracy in our estimates related to sand reserves could result in lower than expected revenues and higher than expected costs, which could have a material adverse effect on our financial results.

Our agreement with a sand supplier includes significant take-or-pay obligations and other risks.

In order to secure a sufficient source of sand to perform under our agreement with Shell and other future hydraulic fracturing service arrangements, we have entered into a four-year agreement with a sand supplier that contains provisions under which we are required to take delivery of a certain annual volume of sand or pay the seller for the volume difference between the required quantity and the volume actually purchased. The agreement fixes a price per ton of sand for the four-year period, subject to an annual increase or decrease of not more than 5% if such adjustment is agreed upon by the parties. Please see the section titled “Business—Sand Purchase Agreement” for additional information. If we are unable to generate sufficient cash from operations or obtain alternative financing, our cash position may not be sufficient to pay for the take-or-pay volumes.

The agreement also requires advance payments totaling $15 million, and the supplier’s performance is contingent on its construction of a new plant, which we expect to be completed by September 2012. If the plant is not constructed as planned, we may be unable to obtain a sufficient source of alternate sand at favorable rates. Moreover, we have limited contractual remedies with respect to any advance payments we may have made, and any litigation we may institute to seek recovery of such advance payments likely would be costly and time-consuming, and the outcome of such litigation would be uncertain.

Federal, state, regional and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our support services.

The federal Safe Drinking Water Act (the “SDWA”) regulates the underground injection of substances through the Underground Injection Control (the “UIC”) program. Due to a 2005 amendment to the SDWA, hydraulic fracturing generally has been exempt from regulation under the UIC program except for the underground injection of hydraulic fracturing fluids or propping agents that contain diesel fuels. As a result, hydraulic fracturing is typically regulated by state environmental regulators or oil and gas commissions and not pursuant to the SDWA. However, the EPA believes that hydraulic fracturing with fluids containing diesel fuel are subject to regulation under the UIC program, specifically as “Class II” UIC wells and can be regulated through the use of Emergency Orders under the SDWA.

In addition, the EPA has commenced a study, at the order of the U.S. Congress, of the potential environmental and health impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. As part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives for federal regulation of hydraulic fracturing under the SDWA or otherwise. Legislation, which has not passed, has been introduced before.

Congress in the last few sessions to remove the exemption of hydraulic fracturing under the SDWA and to require disclosure to a regulatory agency of chemicals used in the fracturing process. In addition, on October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. The adoption of new federal laws or regulations imposing reporting obligations on, or otherwise limiting or regulating, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, increase our and our customers’ costs of compliance, and adversely affect the hydraulic fracturing services that we render for our E&P customers.

rule requires the use of reduced emission (or “green”) completions. The rule also establishes specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks gas processing plants and certain other equipment. This rule may require a number of modifications to our and our customers’ operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs, for us and our customers which may adversely impact 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 and regional governmental 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 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 that may be imposed in connection with the granting of the permit. In addition, there is an opportunity for public comment or challenge with respect to certain permit applications.

Various state, regional and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as certain watersheds. For example, Colorado, Texas and Wyoming have passed laws and regulations requiring the disclosure of information regarding the substances used in the hydraulic fracturing process and other states are considering similar requirements. The availability of information regarding the constituents of hydraulic fracturing fluids could potentially make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

In addition, a number of states have conducted, are currently conducting, or may in the future conduct, regulatory reviews that potentially could restrict or limit our customers’ access to shale formations located in their states. In some jurisdictions, including 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. See the section titled “Business—Environmental Matters.”

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, hydraulic fracturing could make it more difficult to complete natural gas wells in shale formations, increase costs of compliance, and adversely affect the hydraulic fracturing services that we render for our E&P customers. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

Our executive officers and certain key personnel are critical to our business and these officers and key personnel may not remain with us in the future.

Our future success depends upon the continued service of our executive officers and other key personnel, particularly Michel B. Moreno, our Chief Executive Officer, Enrique “Rick” Fontova, our President, and Earl Blackwell, our Chief Financial Officer. If we lose the services of Mr. Moreno, Mr. Fontova or Mr. Blackwell, our other officers or other key personnel, our business, operating results and financial condition could be harmed. Additionally, proceeds from the key person life insurance on any of Mr. Moreno, Mr. Fontova or Mr. Blackwell would not be sufficient to cover our losses in the event we were to lose any of their services.

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

As of March 31, 2012, 57.0% of our revenues were from our top five customers and our top ten customers accounted for 72.6% of our revenue. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer fails to pay us or decides not to continue to use our services, revenue could decline and our operating results and financial condition could be harmed.

If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage over other companies.

Certain technologies used in our business provide us with a competitive advantage over other companies that we believe will increase our market share. We attempt to protect these technologies and competitive advantages by protecting our intellectual property rights via trademark, copyright and trade secret laws, as well as licensing agreements and third-party non-disclosure and assignment agreements. While we do have an exclusive license under a third-party patent application claiming certain TFP technology, we do not have our own patents or patent applications relating to many of our key processes or technology. We attempt to protect these processes and technology as unpatented proprietary technology. Among such technology are trade secrets that we believe provide us with a competitive advantage, including proprietary designs we use in fabricating our hydraulic fracturing units. It is possible that others will independently develop the same or similar technology or otherwise obtain access to the unpatented technology that we license. To protect our trade secrets and other proprietary information, we often require employees, consultants, advisors and collaborators to enter into confidentiality agreements. We cannot assure you that these agreements will provide meaningful protection for our trade secrets, know-how or other proprietary information in the event of any unauthorized use, misappropriation or disclosure of such trade secrets, know-how or other proprietary information. Our failure to obtain or maintain adequate protection of our intellectual property rights for any reason or our inability to prevent competitors from replicating our technology could have a material adverse effect on our business, results of operations and financial condition.

We have secured exclusive rights, through our supply agreements with TPT, to certain TFP technology held by TPT relating to the Frac Stack Pack^TM configuration. Some of this TFP technology is the subject of a non-provisional patent application filed in the United States Patent and Trademark Office on August 25, 2011. Please see the section titled “Business—Intellectual Property Rights” and “Certain Relationships and Related Person Transactions—Joint Venture” for additional information. We cannot assure you that this patent application will be approved. We also cannot assure you that the patents issuing as a result of this or any future domestic or foreign patent applications will have the same scope of coverage as the application as filed. If issued, the patent could be challenged, invalidated or circumvented by others and may not be of sufficient scope or strength to provide us with any meaningful protection. Further, we cannot assure you that competitors will not infringe the patent, or that we will have adequate rights or resources to enforce the patent. Many patent applications in the United States are maintained in secrecy for a period of time after they are filed, and since publication of discoveries in the scientific or patent literature tends to lag behind actual discoveries by several months, we cannot be certain that our licensor was the first creator of the invention covered by the patent application made or that it was the first to file a patent application for the invention. Because some patent applications are maintained in secrecy for a period of time, there is also a risk that we could adopt a technology without knowledge of a pending patent application, which technology would infringe a third party patent once that patent is issued.

If third parties claim that we infringe upon their intellectual property rights, our operating profits could be adversely affected.

We face the risk of claims that we have infringed third parties’ intellectual property rights. For example, our equipment and manufacturing operations may unintentionally infringe upon the patents of a competitor or other

company that uses patented components or processes in its manufacturing operations, and that company may have legal recourse against our use of its protected information. Our competitors, many of which have substantially greater resources and may have made substantial investments in competing technologies, may have applied for or obtained, or may in the future apply for and obtain, patents that will prevent, limit or otherwise interfere with our ability to make and sell our services. We have not conducted an independent review of patents issued to third parties. The large number of patents, the rapid rate of new patent issuances, the complexities of the technology involved and uncertainty of litigation increase the risk of business assets and management’s attention being diverted to patent litigation. In addition, because of the recent introduction to the market of TFP technology, claims that its use infringe on the patent rights of others are more likely to be asserted after more widespread use. We also face the risk of claims that we have misappropriated third parties’ trade secret information.

Any claims of patent or other intellectual property infringement, even those without merit, could:

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be expensive and time consuming to defend;

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cause us to cease making, licensing or using services and products that incorporate the challenged intellectual property;

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require us to redesign or reengineer our products, if feasible;

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divert management’s attention and resources; or

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require us to enter into royalty or licensing agreements in order to obtain the right to use a third party’s intellectual property.

Any royalty or licensing agreements, if required, may not be available to us on acceptable terms or at all. A successful claim of infringement against us could result in our being required to pay significant damages, enter into costly license or royalty agreements, or stop the sale of certain services and products, any of which could have a negative impact on our operating profits and harm our future prospects.

New technology may cause us to become less competitive.

The oilfield service 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 services and 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.

We are vulnerable to the potential difficulties associated with rapid growth and expansion.

We intend to grow rapidly over the next several years. We believe that our future success depends on our ability to manage the growth we expect to occur and the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:

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lack of sufficient executive-level personnel;

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increased administrative burden;

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long lead times associated with acquiring additional equipment, including potential delays with respect to our on-order fracturing units; and

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

In addition, we may in the future seek to grow our business through acquisitions that enhance our existing operations. The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our operating results could be adversely affected if we do not successfully manage these potential difficulties.

We may be unable to employ a sufficient number of skilled and qualified workers.

The delivery of our services and products requires personnel with specialized skills and experience who can perform physically demanding work. As a result of the volatility in the energy service industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in our geographic areas of operations is high, and the supply is limited. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Our operations are subject to hazards inherent in the energy services industry.

Risks inherent to our industry, such as equipment defects, vehicle accidents, explosions and uncontrollable flows of the chemicals we use in hydraulic fracturing as well as gas or well fluids, can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruption and damage to, or destruction of property, equipment and the environment. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. The existence, frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable, which could cause us to lose customers and substantial revenues.

Our operational personnel have experienced accidents which have, in some instances, resulted in serious injuries. Our safety procedures may not always prevent such damages. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations and cash flows.

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

Historically, we have funded the growth of our operations and equipment purchases from bank debt, capital contributions from our equity sponsors and cash generated by our business. If we do not generate sufficient cash from operations to expand our business, our growth could be limited unless we are able to obtain additional capital through equity or debt financings or bank borrowings. Our inability to grow our business may adversely impact our ability to sustain or improve our profits.

Our industry is highly competitive and we may not be able to provide services that meet the specific needs of oil and natural gas E&P companies at competitive prices.

Our industry is highly competitive. The principal competitive factors in our markets are generally technical expertise, fleet capability and experience. We compete with large national and multi-national companies that

have longer operating histories, greater financial resources and greater name recognition than we do and who can operate at a loss in the regions in which we operate. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, competition among oilfield service and equipment providers is affected by each provider’s reputation for innovation, safety and quality. Our reputation for safety and quality may not be sufficient to enable us to maintain our competitive position.

MMH has significant influence over us, including influence over decisions that require stockholder approval, which could limit your ability to influence the outcome of key transactions, including a change of control.

MMH holds 88.9% of our outstanding common stock without giving effect to the exercise of the warrants. As a result, MMH has significant influence over our decisions to enter into any corporate transaction regardless of whether others believe that the transaction is in our best interests.

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

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

Weather conditions could materially impair our business.

Our current and future operations, which may extend into Louisiana and parts of Texas, may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. Adverse weather can also directly impede our own operations. Repercussions of severe weather conditions may include:

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curtailment of services;

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

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

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increase in the price of insurance; and

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loss of productivity.

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

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for our services.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate

changes. Based on these findings, the EPA has begun to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act (the “CAA”). The EPA recently adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which, known as the “Tailoring Rule,” will require that certain large stationary sources obtain permits for their emissions of GHGs. The EPA has also adopted rules requiring the reporting of GHG emissions from certain large GHG emission sources, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

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

Any new federal, regional or state restrictions on emissions of carbon dioxide or other GHGs that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such restrictions could potentially make our customers’ products more expensive and thus reduce demand for them, which could have a material adverse effect on the demand for our services and our business. Finally, some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our results of operations.

We, and our customers, are subject to extensive and costly environmental, health and safety laws and regulations that may require us to take actions that will adversely affect our results of operations.

Our business, and our customers’ business, is significantly affected by stringent and complex federal, state and local laws and regulations governing the discharge of substances into the environment or otherwise relating to protection of the environment or human health and safety. As part of our business, we emit, handle, transport, and dispose of a variety of fluids and substances used by our customers in connection with their oil and natural gas E&P activities. We also generate and dispose of hazardous waste. The emission, generation, handling, transportation, and disposal of these fluids, substances, and wastes are regulated by a number of laws, including the CAA, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation, and Liability Act, the Clean Water Act, the SDWA, and analogous state laws and regulations. Failure to properly handle, transport, or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws and regulations could expose us to liability for governmental penalties, third-party claims, cleanup costs associated with releases of such materials, damages to natural resources, and other damages, as well as potentially impair our ability to conduct our operations. We could be exposed to liability for cleanup costs, natural resource damages and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. We could also be subject to private party tort claims in connection with actual or alleged environmental impacts associated with our operations.

construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose substantial liabilities on us for pollution resulting from our operations. Environmental laws and regulations have changed in the past, and they are likely to change in the future. If existing regulatory requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.

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

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issuance of material administrative, civil and criminal penalties;

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modification, denial or revocation of permits or other authorizations;

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imposition of limitations on our operations; and

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performance of site investigatory, remedial or other corrective actions.

The oil and gas industry presents environmental risks and hazards and environmental regulation has tended to become more stringent over time. Environmental laws and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. In addition, an increase in regulatory requirements on oil and gas exploration and completion activities could significantly delay or interrupt our customers’ operations.

More stringent trucking regulations may increase our costs and negatively impact our results of operations.

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

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

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

Use of Proceeds

All of the common stock referred to in this offering will be offered by the selling shareholders. We will not receive any proceeds from the resale of the common stock by those selling shareholders. We will receive proceeds in the amount of $0.01 per share when the selling shareholders exercise the 250,000 warrants entitling them to purchase 247,058 shares of common stock that they may sell from time to time. If all warrants are exercised, we will receive $2,470.58, which will be used for general corporate purposes.

Dividend Policy

We have not paid dividends on our common stock, and we do not anticipate paying dividends on our common stock in the foreseeable future. In addition, the terms of our senior credit facility and the indenture governing the 13% notes restrict our ability to pay dividends on the common stock.

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our audited consolidated financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about our operations, the hydraulic fracturing services industry and the broader oil and natural gas exploration and production industry. These forward-looking statements involve known and unknown risks, uncertainties and other facts outside of our control that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to: general economic and competitive conditions, changes in market prices for oil and natural gas, the level of oil and natural gas drilling and corresponding increases or decreases in the demand for our services, the level of capital expenditures by our existing and prospective customers, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in the sections titled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.” We undertake no obligation to update any forward-looking statements, even if new information becomes available or other events materially impact any of the forward-looking statements contained in this prospectus.

Overview

How We Generate Our Revenues

Historically, our revenue has been derived from the performance of well services. Since December 2010, we have provided hydraulic fracturing services that we believe will provide us with additional revenue. In the future, we expect that a majority of our revenue will come from hydraulic fracturing services.

Hydraulic Fracturing Services. We intend to provide hydraulic fracturing and other services to our customers through three different types of customer arrangements:

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per-stage payments for the committed hydraulic fracturing spreads under long-term agreements, such as our agreement with Shell;

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contracts providing minimum monthly service fees; and

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spot market arrangements to provide hydraulic fracturing services at prevailing market rates.

Under any of these arrangements, the fees we charge per fracturing stage will be based on the equipment and personnel required for the job, the flow rate and pressures in the hydraulic fracturing pumps, market conditions in the region in which the services are performed as well as the type and volumes of chemicals and proppants that are consumed during the fracturing process.

With respect to our turbine-powered hydraulic fracturing fleet, in September 2011 we entered into a two-year agreement with Shell to provide Shell with hydraulic fracturing services. We delivered our first hydraulic fracturing unit pursuant to our Shell agreement during the first quarter of 2012.

We expect that our long-term contracts will likely require that we provide our hydraulic fracturing equipment, the crew to operate that equipment and the required fuel, chemicals and proppant, and our customers will generally be charged per fracturing stage completed. We expect that our contracts for minimum monthly services will be for multiple-year terms and our customers will agree to pay us on a monthly basis for a specified number of fracturing stages, whether or not those stages are actually fractured. To the extent customers utilize more than the specified contract minimums, we will likely be paid an agreed-upon amount per stage actually fractured.

Although we have entered into the Shell agreement and will seek additional term contracts for our remaining hydraulic fracturing fleet, we intend to have the flexibility to pursue short-term engagements with multiple customers. We will charge prevailing market prices per stage for this work. We believe our ability to provide services in the spot market will allow us to take advantage of any favorable pricing that may exist in this market and will allow us to develop new customer relationships. Under the term contracts and for spot market work, we may also charge fees for set up and mobilization of equipment, depending on the job.

We have entered into a lease for two sand mines and expect to generate revenue from third-party sales of sand. We expect the sand from these mines to satisfy a portion of our own fracturing sand needs as well as provide us the opportunity to sell fracturing sand to third parties. We have also entered into an agreement with Alliance Consulting Group, an affiliate, to build and operate a wet and dry processing plant that will perform the mining, processing and transportation of raw fracturing sand from these mines to support a portion of our own fracturing sand needs as well as demand from other consumers of fracturing and other types of sand. We will pay Alliance $29 per ton for these services and as of June 8, 2012 had prepaid Alliance $4 million which will offset future costs.

We have received inquiries from a number of oilfield service companies, including some subsidiaries of E&P companies, regarding possible sale or lease arrangements for our TFPs. We may consider entering into selective sale or lease arrangements to generate near-term cash flow and profitability while we continue to build out our fracturing operations. We expect that we would enter into such an arrangement only in situations in which we would not have the opportunity to provide such services or if our customer agrees that it will not develop or use turbine fracturing technology other than ours for a reasonable period of time.

Well Services. Our revenue from well services has been, and we believe will continue to be, derived from prevailing market rates for such services, together with associated materials charges. We intend to expand our well services capacity and, to that end, plan to add new cementing and coiled tubing units to our fleet.

Our cementing, coiled tubing, pressure pumping, acidizing and other pumping services are provided in the spot market at prevailing prices per job. We may also charge fees for set up and mobilization of equipment in certain circumstances. The set-up charges and project rates vary with the type of service to be performed, the equipment and personnel required for the job, the distance of the project from our equipment and market conditions in the region in which the service is to be performed. We also charge customers for the materials, such as stimulation fluids, nitrogen, acids and cement, that we use in each job. Materials charges reflect the cost of the materials plus a markup and are based on the actual quantity of materials used in the project. We have entered into MSAs with approximately 90 oil and natural gas companies that enable us to provide well services to those companies on request.

How We Manage Costs and Secure Critical Equipment

The principal expenses involved in conducting our business are the costs of acquiring, maintaining and repairing our equipment, labor and related personnel expenses, product and material costs and fuel costs. Additionally, we will incur costs to deliver and stage our hydraulic fracturing spreads to the worksite.

We purchase our hydraulic fracturing components, including turbine engines, pumps, skids, instrumentation and gear boxes, from third-party vendors, and we then oversee the assembly of the components into TFPs, which we believe provides us access to end products in a timely and more cost-effective manner than purchasing fully constructed components from third parties. Certain installation services necessary for the manufacture of TFPs is provided by TPT under the terms of our installation agreement with it. Please see the section titled “Certain Relationships and Related Person Transactions—Joint Venture” for additional information.

A critical element of our ability to accurately predict and manage the costs of assembling our TFPs is an exclusive agreement TPT has with a vendor that provides remanufactured turbine engines previously used in U.S. military applications. Under our equipment purchase agreement with TPT, we have negotiated a fixed price for

up to 172 turbine engines, including 53 in inventory as of June 8, 2012. We believe the reliability of our turbine supply will be a key aspect of our future success as we continue to grow our hydraulic fracturing fleet.

Preventative maintenance on our equipment is an important factor in our profitability. If our equipment is not maintained properly, our repair costs may increase and, during periods of high activity, our ability to operate efficiently could be significantly diminished due to having equipment out of service. Our maintenance crews perform regular inspections and preventative maintenance on each of our trucks and other mechanical equipment. Our management monitors the performance of our maintenance crews at each of our service centers by monitoring the level of maintenance expenses over time and comparing those expenses to budgeted maintenance expenses. A rising level of maintenance expenses over time relative to budgeted amounts can be an early indication that our preventative maintenance schedule is not being followed or that certain of our equipment is in need of major repair or replacement. In this situation, management can take corrective measures to help reduce maintenance expenses as well as ensure that maintenance issues do not interfere with operations. With respect to our hydraulic fracturing fleet, because our TFPs will be assembled using newly remanufactured turbine engines and other new components, we anticipate that our down time for maintenance and repair will initially be lower than our competitors whose hydraulic fracturing equipment has been in use for some time.

We will incur significant fuel consumption in connection with the operation of our hydraulic fracturing fleet and the transportation of our equipment and products. However, the ability of our TFPs to utilize natural gas, diesel or biofuel allows us to select the lowest-cost fuel in each market in which we operate.

Raw fracturing sand is an essential element of the proppant used in the fracturing process. We have entered into a lease for two sand mines and expect to generate revenue from third-party sales of sand once we invest in new mining and refining equipment and develop the infrastructure to transport the raw fracturing sand from the mines to the final point of sale. We believe our sand operations will provide a reliable, cost-effective source of raw fracturing sand for certain of our jobs. We expect the sand from these mines to satisfy a portion of our own fracturing sand needs as well as provide us the opportunity to sell fracturing sand to third parties. Based on a report prepared by Terracon Consultants, Inc., such mines have an estimated 26 million tons of proven reserves that fall within the sieve size range traditionally used in fracturing operations.

Depreciation and amortization represented approximately 33.6% of our revenues for the year ended December 31, 2011 and 48.6% of our revenues for the three months ended March 31, 2012. Direct labor costs represented approximately 20.6% of our revenues for the year ended December 31, 2011 and 60.2% of our revenues for the three months ended March 31, 2012. Other direct costs, including proppant, chemical and freight costs, represented approximately 27.1% of our revenues for the year ended December 31, 2011 and 79.5% of our revenues for the three months ended March 31, 2012. Indirect costs represented approximately 29.2% of our revenues for the year ended December 31, 2011 and 69.2% of our revenues for the three months ended March 31, 2012.

How We Manage Our Operations

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

Asset Utilization. With respect to hydraulic fracturing services, we will measure our activity levels by the total number of hydraulic fracturing stages completed per month by each of our hydraulic fracturing spreads. With respect to our well services, we measure our activity levels by the total number of jobs completed per month. We may also track the number of wells we have serviced in connection with analyzing our fracturing stage count. We also monitor the number of requests we receive for our services and equipment, as well as the number of times either we or our customers decline a job request because of pricing or equipment availability. By consistently monitoring the activity level, pricing and relative performance of each of our spreads and jobs, we can more efficiently allocate our equipment and personnel to maximize our revenue generation and profitability.

We began completing stages with our first hydraulic fracturing spread in December 2010. During the three months ended March 31, 2012, we completed 14 fracturing stages and generated average revenue per fracturing stage of $110,585. We also participated in another 6 stages in which we were not operator. Also during the three months ended March 31, 2012, we completed 521 well services jobs, generating average revenue per job of $8,482.

Customer Satisfaction. We value our longstanding relationships with our producer customers. We regularly review changes in our revenue per customer to assess each customer’s level of demand for, and satisfaction with, our services. Our management also uses this information to evaluate our position relative to our competitors in the various markets in which we operate.

Safety Performance. Maintaining a strong safety record is a critical component of our operational success. Many of our customers have safety standards we must satisfy before we can perform services for them. We maintain a safety database which allows management to identify negative trends in operational incidents so that appropriate measures can be taken to maintain and enhance our safety standards. We believe our outstanding safety record and proactive behavior-based safety program are significant contributors to our ability to maintain strong customer relationships and gain new work.

Our Challenges

We face many challenges and risks in the industry in which we operate. Although many factors contributing to these risks are beyond our ability to control, we continuously monitor these risks, and we have taken steps to mitigate them to the extent practicable. In addition, we believe that we are well positioned to capitalize on the current growth opportunities available in the hydraulic fracturing market. However, we may be unable to capitalize on our competitive strengths to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read the section titled “Risk Factors” in this prospectus for additional information about the risks we face.

Attracting and Retaining Operational Personnel. Our ability to provide services profitably and to expand our operations depends on our ability to attract and retain experienced, knowledgeable and skilled operational employees. The demand for skilled workers in our geographic areas of operations is high, resulting in intense competition among oilfield services companies for skilled workers. In addition, we are likely to face increased competition for skilled personnel as new and existing oilfield services companies enter or expand their operations in the hydraulic fracturing sector. We believe that the following elements will help us meet this challenge:

•

the fact that our TFPs require fewer employees per job than conventional diesel-powered hydraulic fracturing equipment;

•

the appeal of operating and being associated with equipment that utilizes the Frac Stack Pack™ technology;

•

our competitive compensation and benefits package; and

•

the ease of operating our turbine-powered hydraulic fracturing equipment relative to conventional diesel-powered equipment.

Hydraulic Fracturing Legislation and Regulation. Hydraulic fracturing generally has been exempt from federal regulation under the SDWA since 2005 except for the underground injection of hydraulic fracturing fluids or propping agents that contain diesel fuels. Our hydraulic fracturing operations do not include the underground injection of hydraulic fracturing fluids or propping agents that contain diesel as a constituent. Legislation has been introduced before Congress in the last few sessions to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Although the federal legislation did not pass, if similar federal legislation is introduced and becomes law in the future, the legislation could establish an additional level of regulation that could lead to operational delays or increased operating costs. The EPA commenced a study, at the order of Congress, of the potential environmental and health impacts of hydraulic

fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. On October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. The EPA is also using administrative Emergency Orders under the SDWA to regulate certain hydraulic fracturing activities. In addition, various state, regional and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing, and Texas and other states have adopted legislation that requires disclosure of information regarding the substances used in the hydraulic fracturing process to state regulators and the public.

On April 17, 2012 the EPA approved final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. This new rule addresses emissions of various pollutants frequently associated with oil and natural gas production and processing activities. For new or reworked hydraulically-fractured wells, the final rule requires controlling emissions through flaring until 2015, when the rule requires the use of reduced emission (or “green”) completions. The rule also establishes specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks gas processing plants and certain other equipment. This rule may require a number of modifications to our and our customers’ operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs, for us and our customers which may adversely impact our business.

The EPA has also implemented its Tier 4 regulations, which, among other things, set emission standards for certain off-road diesel engines that are used to power equipment in the field. Field tests regarding operation of our current turbine-powered hydraulic fracturing units have demonstrated compliance with the Tier 4 standards with respect to NOx and carbon monoxide emissions. Further emissions controls may be required with respect to other emissions regulated by Tier 4 standards, including particulate matter. We currently expect to conduct further Tier 4 emissions testing in the second quarter of 2012 on certain of our new hydraulic fracturing units. We believe our turbine-powered fleet’s fuel flexibility provide us with significant advantages relative to many of our competitors in meeting any newly proposed standards.

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting or regulating, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, increase our and our customers’ costs of compliance, and adversely affect the hydraulic fracturing services that we render for our E&P customers. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting or regulatory requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

Equipment Supply. The overall number of hydraulic fracturing equipment suppliers in the industry in which we operate is limited, and there has historically been high demand for this equipment. As of June 8, 2012, our fleet has 108,000 HP of turbine-powered high pressure pumping capacity and commitments of $68 million for the purchase of additional equipment. With our current customer commitments and in light of current market conditions, we intend to expend only an approximate $33.2 million for the remainder of 2012 to acquire hydraulic fracturing and well services equipment to add another 46,000 HP of turbine-powered high pressure capacity to our fleet and six coiled tubing units. We now plan to have a fleet with approximately 154,000 HP of turbine-powered high pressure capacity. We do not anticipate adding more horsepower without additional firm customer commitments in the future and we may also consider reconfiguring or selling some portion of the earlier assembled units in the fleet based on customer commitments and our evaluation of the market over the near term.

Financing Future Growth. Historically, we have funded our growth through capital contributions, borrowings from equity holders and third parties, proceeds of our unit offering and cash generated from our operations. With the cash consumed under our capital expansion program to serve the hydraulic fracturing market, and the recent delay in commencing operations during the first quarter of 2012, we are managing our cash expenditures to

complete additional hydraulic fracturing spreads consistent with firm customer commitments. Our original plan called for a fleet with 234,000 HP of turbine-powered high pressure pumping capacity. As of June 8, 2012, our fleet has 108,000 HP of turbine-powered high pressure pumping capacity and commitments of $68 million for the purchase of additional equipment. With our current customer commitments and in light of current market conditions, we intend to expend only an approximate $33.2 million for the remainder of 2012 to acquire hydraulic fracturing and well services equipment to add another 46,000 HP of turbine-powered high pressure capacity to our fleet and six coiled tubing units. We now plan to have a fleet with approximately 154,000 HP of turbine-powered high pressure capacity. We do not anticipate adding more horsepower without additional firm customer commitments in the future and we may also consider reconfiguring or selling some portion of the earlier assembled units in the fleet based on customer commitments and our evaluation of the market over the near term. We believe that we will have sufficient working capital to complete the procurement and assembly of the equipment needed to reach the 154,000 HP fleet size. In addition to our funds we expect to generate from operations, we may obtain working capital through borrowings from existing equity holders or third parties, the sale of turbine fracturing equipment and sand inventory, or the sale of additional common stock if needed to complete our fleet expansion to 154,000 HP. We believe we can defer or cancel the remaining equipment commitments we currently have at a minimal cost.

Recent Developments

Senior Credit Facility. In April 2012 we entered into an Amendment to the Shell agreement (the “Amendment”), to add a senior credit facility and amend the provisions of the security agreement contained in the Shell agreement.

The Amendment commits Shell to provide advances to the Company in four tranches. The first three tranches are of $30 million each and the last tranche is of $10 million. The first tranche was advanced in May 2012. Each tranche requires repayments of a portion of the amount advanced to be made on a monthly basis with the succeeding tranche to be disbursed upon written notice of repayment of the previous tranche and request for payment of the succeeding tranche within seven days of such repayment. The amounts advanced under the senior credit facility do not bear interest. Each tranche is to be repaid according to the schedule shown in the table below:


	Repayment Date	Repayment Amount
Tranche 1 $30 million	June 15, 2012	$	2,000,000.00
	July 15, 2012	$	2,000,000.00
	August 15, 2012	$	2,000,000.00
	September 15, 2012	$	2,000,000.00
	October 15, 2012	$	2,000,000.00
	November 15, 2012	$	2,000,000.00
	December 15, 2012	$	7,333,333.33
	January 15, 2013	$	7,333,333.33
	February 15, 2013	$	3,333,333.34

Tranche 2 $30 million	March 15, 2013	$	7,333,333.33
	April 15, 2013	$	7,333,333.33
	May 15, 2013	$	7,333,333.33
	June 15, 2013	$	8,000,00.01

Tranche 3 $30 million	July 15, 2013	$	7,333,333.33
	August 15, 2013	$	7,333,333.33
	September 15, 2013	$	7,333,333.33
	October 15, 2013	$	8,000,000.01

Tranche 4 $10 million	November 15, 2013	$	5,000,000.00
Tranche 4 $10 million	December 15, 2013	$	5,000,000.00

Please see the section titled “Business—Shell Agreement” for additional information.

In connection with our senior credit facility, we entered into an intercreditor agreement with SWEP I, LP (“Shell”), Hub City Tools, Inc. and Wilmington Trust, National Association. The terms of the intercreditor agreement are consistent with the intercreditor agreement attached as an exhibit to our indenture.

Effects of Inflation

Inflation did not have a material impact on our results of operations for the years ended December 31, 2010 or 2009. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Critical Accounting Policies

Certain accounting policies require the application of judgment by management in selecting appropriate assumptions for calculating financial estimates, which inherently contain some degree of uncertainty. Management bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the reported carrying values of assets and liabilities and the reported amounts of revenue and expenses that may not be readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We believe the following are some of the more critical accounting policies and related judgments and estimates used in the preparation of its consolidated financial statements: revenue recognition, impairment of long-lived assets, impairment of intangible assets and goodwill, contingent consideration valuation, and business combination accounting.

See the Notes to our audited and unaudited consolidated financial statements included elsewhere in this prospectus for additional information on accounting policies affecting our financial condition and results of operations.

Results of Operations

In the near term, we expect that our revenues and results of operations will be positively impacted by increased utilization and improved pricing for our well services equipment and the hydraulic fracturing services revenue generated by growth in our fleet of hydraulic fracturing spreads. We expect that our results of operations in 2012 compared to 2011 will be significantly impacted by the growth of our asset base during the year 2012.

Results for the three months ended March 31, 2012 Compared to the three months ended March 31, 2011

The following table summarizes the change in our results of operations for the three months ended March 31, 2012 when compared to the three months ended March 31, 2011:


	PREDECESSOR			SUCCESSOR
	THREE MONTHS ENDED MARCH 31, 2011			THREE MONTHS ENDED MARCH 31, 2012			$ CHANGE
Statement of Operations Data:
Revenue	$	10,514		$	6,277		$	(4,237	)
Operating costs:
Costs of revenue		7,349			13,117			5,578
Selling and administrative expenses		1,282			5,515			4,233
Depreciation and amortization		1,279			3,070			1,791

Total operating costs		9,910			21,702			11,792

Income (loss) from operations		604			(15,425	)		(16,029	)
Other income (expense)
Interest income		0			7			7
Interest expense		(287	)		(4,794	)		(4,507	)
Other income (expense)		(166	)		(6	)		160

Net other expense		(453	)		(4,793	)		(4,340	)

Income (loss) before income taxes		151			(20,218	)		(20,369	)
Income tax expense (benefit)		46			2			(44	)

Net income (loss)	$	105		$	(20,220	)	$	(20,325	)

(in thousands)

Revenue

Revenue decreased $4.2 million, or 40.3%, to $6.3 million for the three months ended March 31, 2012 as compared to $10.5 million for the same period in 2011. This decrease was due primarily to the reduction of well service revenues and hydraulic fracturing service revenues as a result of the reassignment of certain well service equipment in support of the first hydraulic fracturing spread and the under-utilization of the first hydraulic fracturing spread in the quarter ended March 31, 2012. During the three months ended March 31, 2012, our hydraulic fracturing spreads in service completed 14 well stages. We also participated in another 6 stages in which we were not operator. As of May 21, 2012 our hydraulic fracturing spreads had completed an additional 74 well stages.

Costs of Revenue

Costs of revenue increased $5.8 million, or 78.5%, to $13.1 million for the three months ended March 31, 2012 as compared to $7.3 million for the same period in 2011. This increase was primarily due to an increase in operating activity relating to preparation for deployment and the operation of new hydraulic fracturing equipment. The most significant increases were in the costs of products (such as sand and chemicals), freight, direct labor and repairs and maintenance costs. The net effect of the increase in our costs of revenue along with an under-utilization of our hydraulic fracturing equipment was an increase in our costs as a percentage of revenue to 209.0% for the three months ended March 31, 2012 from 69.9% for the same period in 2011.

Selling and Administrative Expenses

Selling and administrative expenses increased $4.2 million, or 330.4%, to $5.5 million for the three months ended March 31, 2012 as compared to $1.3 million for the same period in 2011. This increase was primarily due to an increase in costs associated with senior management and administrative personnel additions and the overall

growth of our organization. The most significant increases were in administrative wage and benefits costs and selling and senior management travel related costs. Additionally, during the three months ended March 31, 2012, we recorded bonus compensation expense of $0.0 million and bad debt expense of $0.0 million as compared to $0.2 million and $0.0 million, respectively, for the same period in 2011. As a percentage of revenue, selling and administrative expense increased to 87.9% for the three months ended March 31, 2012 as compared to 12.2% for three months ended March 31, 2011.

Depreciation and Amortization

Depreciation and amortization expense increased $1.8 million, or 140.0%, to $3.1 million for the three months ended March 31, 2012 as compared to $1.3 million for the same period in 2011. The increase was primarily due to the depreciation expense related to a “step-up” in basis relating to a change in control which occurred in May 2011, an increase of $31.2 million to assets in service, amortization expense relating to the intangible assets that resulted from the change in control, and amortization expense relating to the issuance of the 13% notes that occurred in November 2011. As a percentage of revenue, depreciation and amortization increased to 48.9% for the three months ended March 31, 2012 as compared to 12.2% for the same period in 2011. In addition to the foregoing, this increase was also due to less than full utilization of our hydraulic fracturing equipment in service during the three month period ended March 31, 2012.

Interest Expense

Interest expense increased $4.5 million, or 1,570.2%, to $4.8 million for the three months ended March 31, 2012 as compared to $0.3 million for the same period in 2011. This increase was primarily due to an increase in the average interest rate applicable and the increase in outstanding borrowings as a result of the significant increase in capital expenditures during the three months ended March 31, 2012 as compared to the average interest rate applicable, the level of outstanding borrowings and capital expenditures for the same period in 2011.

Other Income (Expense)

Other expense decreased $0.2 million, or 96.5%, to $0.0 million for the three months ended March 31, 2012 as compared to $0.2 million for the same period in 2011. This decrease was primarily due to administrative fees of $0.0 million and $0.2 million for the three months ended March 31, 2012 and March 31, 2011, respectively.

Income Tax Expense (Benefit)

Income tax expense remained unchanged at $0.0 million for the three months ended March 31, 2012 as compared to $0.0 million for the three months ended March 31, 2012.

Net Income (Loss)

As a result of the foregoing factors, net income decreased by $20.3 million to a net loss of $20.2 million for the three months ended March 31, 2012 as compared to net income of $0.1 million for same period in 2011.

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

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


	PREDECESSOR			SUCCESSOR			PREDECESSOR
	YEAR ENDED DECEMBER 31, 2010			PERIOD FROM MAY 1, TO DECEMBER 31, 2011			PERIOD FROM JANUARY 1, TO APRIL 30, 2011			$ CHANGE
Statement of Operations Data:
Revenue	$	28,362		$	18,625		$	14,446		$	4,709
Operating costs:
Costs of revenue		16,615			15,601			9,815			8,801
Selling and administrative expenses		4,031			11,654			2,002			9,624
Depreciation and amortization		4,602			9,396			1,724			6,517

Total operating costs		25,249			36,651			13,540			24,943

Income (loss) from operations		3,113			(18,026	)		905			(20,234	)
Other income (expense):
Interest expense		(1,034	)		(4,068	)		(364	)		(3,398	)
Other income (expense)		(468	)		(1,476	)		44			(964	)

Net other expense		(1,503	)		(5,544	)		(320	)		(4,362	)

Income (loss) before income taxes		1,611			(23,570	)		585			(24,595	)
Income tax expense (benefit)		78			52			63			37

Net income (loss)	$	1,533		$	(23,622	)	$	522		$	(24,632	)

(in thousands)

Revenue

Revenue increased $4.7 million, or 16.6%, to $33.1 million for the year ended December 31, 2011 as compared to $28.4 million for the year ended December 31, 2010. This increase was primarily due to an increase in the average revenue per job. For the year ended December 31, 2011, the total number of jobs decreased approximately 28.2% relative to the total number of jobs for the prior year. The total number of jobs worked during the year ended December 31, 2011 decreased as a result of the transition of certain equipment from well services work to hydraulic fracturing and the down time related to preparation of this equipment for deployment.

Costs of Revenue

Costs of revenue increased $8.8 million, or 53.0%, to $25.4 million for the year ended December 31, 2011 as compared to $16.6 million for the year ended December 31, 2010. The increase in costs of revenue was due to an overall increase in operating activity and the addition of certain direct and indirect costs of revenue which are incurred in advance of revenue generation. The most significant increases were in the costs of products (such as sand and chemicals), fuel and oil, direct labor, repairs and maintenance and indirect costs. Our costs increased as a percentage of revenue to 76.9% for the year ended December 31, 2011 compared with 58.6% for the year ended December 31, 2010.

Selling and Administrative Expenses

Selling and administrative expenses increased $9.6 million, or 238.7%, to $13.7 million for the year ended December 31, 2011 as compared to $4.0 million for the year ended December 31, 2010. This increase was primarily due to increases in personnel costs and travel related costs along with significant professional fees all resulting from the growth of our business operations . As a result, selling and administrative expenses increased as a percentage of revenue to 41.3% for the year ended December 31, 2011 compared to14.2% for the year ended December 31, 2010.

Depreciation and Amortization

Depreciation and amortization increased $6.5 million, or 141.6%, to $11.1 million for the year ended December 31, 2011 as compared to $4.6 million for the year ended December 31, 2010. The increase was primarily due to the effect of a full year of depreciation incurred during the year ended December 31, 2011 for the first spread of fracturing equipment which entered service during the fourth quarter of the year ended December 31, 2010. As a percentage of revenue, depreciation and amortization increased to 33.6% in 2011 from 16.2 % in 2010 as a result of less than full utilization of the first spread of fracturing equipment during 2011 and the relatively fixed nature of depreciation and amortization.

Interest Expense

Interest expense increased $3.4 million, or 328.5%, to $4.4 million for the year ended December 31, 2011 as compared to $1.0 million for the year ended December 31, 2010. This increase was primarily due to an increase in the amount of outstanding borrowings and the average interest rates applicable for the year ended December 31, 2011 as compared to the amount of outstanding borrowings and the average interest rates applicable for the prior period year end.

Other Income (Expense)

Other expense increased $1.0 million, or 205.9%, to $1.5 million for the year ended December 31, 2011 as compared to $0.5 million for the year ended December 31, 2010. The increase was primarily due to lender’s facility fees of $1.5 million at December 31, 2011 as compared to $0.5 million at December 31, 2010.

Income Tax Expense (Benefit)

Income tax expense was $0.1 million for the year ended December 31, 2011 as compared to an income tax expense of $0.1 million for the year ended December 31, 2010. These taxes primarily relate to the State of Texas and are generally based on gross revenues earned in the state, less certain deductions.

Net Income (Loss)

As a result of the foregoing factors, net income decreased by $24.6 million, or 1,607.0%, to a net loss of $23.1 million for the year ended December 31, 2011 as compared to a $1.5 million net income for the year ended December 31, 2010.

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

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


	YEAR ENDED DECEMBER 31,
	2009			2010			$ CHANGE
Statement of Operations Data:
Revenue	$	18,140		$	28,362		$	10,223
Operating costs:
Costs of revenue		11,522			16,615			5,094
Selling and administrative expenses		4,218			4,031			(187	)
Depreciation and amortization		3,798			4,602			804

Total operating costs		19,538			25,249			5,711

Income (loss) from operations		(1,398	)		3,113			4,512
Other income (expense):
Interest expense		(1,216	)		(1,034	)		181
Other income (expense)		(709	)		(468	)		241

Net other expense		(1,925	)		(1,503	)		422
Income (loss) before income taxes		(3,323	)		1,611			4,934
Income tax expense (benefit)		(43	)		78			121

Net income (loss)	$	(3,280	)	$	1,533		$	4,813

(in thousands)

Revenue

Revenue increased $10.2 million, or 56.4%, to $28.4 million for the year ended December 31, 2010 as compared to $18.1 million for the year ended December 31, 2009. This increase was primarily due to a significant increase in demand for our well services and in part to an increase in average per job revenues for these jobs. For the year ended December 31, 2010, the total number of jobs increased approximately 34% relative to the total number of jobs for the prior year. We estimate that our average revenue per job for the year ended December 31, 2010 increased approximately 16% as compared to the average revenue per job for the year ended December 31, 2009.

Costs of Revenue

Costs of revenue increased $5.1 million, or 44.3%, to $16.6 million for the year ended December 31, 2010 as compared to $11.5 million for the year ended December 31, 2009. The increase in costs of revenue was primarily due to an overall increase in operating activity. The most significant increases were in the costs of products (such as sand and chemicals), fuel and oil, direct labor, repairs and maintenance and indirect costs relating to the increase in revenue over the same period. As a result our costs decreased as a percentage of revenue to 58.5% for the year ended December 31, 2010 compared with 63.5% for the year ended December 31, 2009 due to an increase in per job revenue.

Selling and Administrative Expenses

Selling and administrative expenses decreased $0.2 million, or 4.8%, to $4.0 million for the year ended December 31, 2010 as compared to $4.2 million for the year ended December 31, 2009. This decrease was primarily due to the general activity of our operations and normal fluctuations in costs from period to period. Selling and administrative expenses decreased as a percentage of revenue to 14.1% for the year ended December 31, 2010 compared to 23.2% for the year ended December 31, 2009.

Depreciation and Amortization

Depreciation and amortization increased $0.8 million, or 21.1%, to $4.6 million for the year ended December 31, 2010 as compared to $3.8 million for the year ended December 31, 2009. The increase was primarily due to the placement into service of our first hydraulic fracturing spread during the fourth quarter of 2010. As a percentage of revenue, depreciation and amortization declined to 16.2% in 2010 from 21.0% in 2009 as a result of the significant increase in revenue and the relatively fixed nature of depreciation and amortization.

Interest Expense

Interest expense decreased $0.2 million, or 16.7%, to $1.0 million for the year ended December 31, 2010 as compared to $1.2 million for the year ended December 31, 2009. This decrease was primarily due to a reduced amount of outstanding borrowings for the year ended December 31, 2010 as compared to the amount of outstanding borrowings at the prior period year end.

Other Income (Expense)

Other expense decreased $0.2 million, or 28.6%, to $0.5 million for the year ended December 31, 2010 as compared to $0.7 million for the year ended December 31, 2009. The decrease was primarily due to a loss on sale of $0.1 million at December 31, 2010 as compared to a loss on sale of $0.5 million at December 31, 2009.

Income Tax Expense (Benefit)

Income tax expense increased $0.1 million to $0.1 million for the year ended December 31, 2010 as compared to $0.0 million for the year ended December 31, 2009. This increase was primarily the result of higher tax expenses relating to the State of Texas, which are generally based on gross revenues, less certain deductions.

Net Income (Loss)

As a result of the foregoing factors, net income increased by $4.8 million, or 145.5%, to $1.5 million for the year ended December 31, 2010 as compared to a $3.3 million net loss for the year ended December 31, 2009.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions and borrowings from our equity holders, the proceeds from the private offering of the 13% notes and other indebtedness and cash generated from our business. Our primary uses of capital have been the acquisition of equipment and general and administrative expenses. We expect cash generated from operations to be a significant source of liquidity during 2012 as we continue to grow and place into service our hydraulic fracturing fleet. In April 2012 we entered into an Amendment to the Shell agreement to add a senior credit facility and amend the provisions of the security agreement contained in the Shell agreement. The Amendment commits Shell to provide advances to the Company in four tranches. The first three tranches are of $30 million each and the last tranche is of $10 million. The first tranche was advanced in May 2012. Each tranche requires repayments of a portion of the amount advanced to be made on a monthly basis with the succeeding tranche to be disbursed upon written notice of repayment of the previous tranche and request for payment of the succeeding tranche within seven days of such repayment. The amounts advanced under the senior credit facility do not bear interest. Please see the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Senior Credit Facility” for a description of the material terms of our senior credit facility.

Our ability to satisfy debt service obligations and to fund planned capital expenditures 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.

Capital Expenditures

The oil and natural gas hydraulic fracturing and well services business is capital-intensive, requiring significant investment to expand, upgrade and maintain equipment. Our capital requirements consist primarily of:

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capital expenditures primarily related to the assembly of our frac spread units through 2012; and

•

maintenance capital expenditures, which are capital expenditures made to extend the useful life of partially or fully depreciated assets.

As of March 31, 2012, we have made capital expenditures of approximately $42.4 million for 2012. As of June 8, 2012 we expect to make approximately $33.2 million of additional capital expenditures through the remainder of 2012. Our capital budget may be adjusted as business conditions warrant. While partially discretionary, the amount, timing and allocation of capital expenditures for 2012 is subject to customer commitments and our evaluation of the market. However, if oil and natural gas prices decline significantly, we could defer a significant portion of our non-contracted budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to our projected needs for new equipment while seeking to maintain our targeted liquidity. See “—Financing Future Growth” for future discussion.

Additionally we will continually monitor service offerings and technologies that may complement our businesses and opportunities to acquire additional equipment to meet our customers’ needs.

We believe that cash on hand, cash flow from operations and cash from financing arrangements will provide sufficient cash to enable us to fund our current operations.

We actively review acquisition opportunities on an ongoing basis. Our ability to make significant acquisitions for cash would likely require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Financial Condition and Cash Flows

The following table sets forth historical cash flows information for each of the three months ended March 31, 2012 and 2011:


	PREDECESSOR			SUCCESSOR
STATEMENT OF CASH FLOWS:	THREE MONTHS ENDED MARCH 31, 2011			THREE MONTHS ENDED MARCH 31, 2012
Cash flows provided by (used in):
Operating activities	$	1,191,270		$	(29,795,586	)
Investing activities		(263,559	)		(42,173,626	)
Financing activities		(909,341	)		2,693,559

Change in cash and cash equivalents	$	18,370		$	(69,275,653	)

Net Cash Flows Provided by (Used in) Operating Activities

Net cash used in operating activities increased $31.0 million, to $29.8 million for the three month period ended March 31, 2012 compared to cash provided by operating activities of $1.2 million for the three month period ended March 31, 2011. For the three months ended March 31, 2012, net cash provided by operating activities consisted primarily of $8.2 million from an increase in accounts payable and $7.2 million from an increase in accrued expenses. Depreciation and amortization represented a $3.1 million adjustments to operating cash flows. Prepaid expenses and inventory increased using net cash of $4.2 million and $19.7 million, respectively. Accounts receivable and other assets increased using net cash of $2.0 million and $3.5 million, respectively.

Net Cash Flows Used in Investing Activities

Net cash used in investing activities increased $41.9 million, to $42.2 million, for the three months ended March 31, 2012 compared to $0.3 million for the same period in 2011. For the three months ended March 31, 2012 net cash used in investing activities consisted primarily of purchases of property, plant and equipment of $42.4 million related to the capital expenditure plan in progress and an investment of $0.5 million in Turbine Powered Technology, L.L.C. which was partially offset by proceeds on the sale of property of $0.2 million. Expenditures included various auxiliary equipment, components needed for the manufacture and assembly of turbine-powered hydraulic fracturing equipment, and well services equipment.

Net Cash Flows Provided by (Used in) Financing Activities

Net cash provided by financing activities increased $3.6 million, to $2.7 million, for the three months ended March 31, 2012 compared to $0.9 million of net cash used by financing activities for the same period in 2011. For the three months ended March 31, 2012 net cash provided by financing activities consisted primarily of $3.0 million in capital lease obligations. Net cash used by financing activities consisted of $0.2 million to repay owners and affiliates and a repayment of principal on long-term debt of $0.1 million.

The following table sets forth historical cash flows information for each of the years ended December 31, 2011, 2010 and 2009:


	PREDECESSOR						COMBINED PREDECESSOR/ SUCCESSOR			PREDECESSOR			SUCCESSOR
	YEAR ENDED DECEMBER 31,									PERIOD FROM JANUARY 1, TO APRIL 30, 2011			PERIOD FROM MAY 1, TO DECEMBER 31, 2011
STATEMENT OF CASH FLOWS:	2009			2010			2011			PERIOD FROM JANUARY 1, TO APRIL 30, 2011			PERIOD FROM MAY 1, TO DECEMBER 31, 2011
Cash flows provided by (used in):
Operating activities	$	3,810		$	3,085		$	2,014		$	2,054		$	(39	)
Investing activities		(3,222	)		(2,421	)		(120,588	)		(256	)		(120,333	)
Financing activities		(1,206	)		(46	)		204,854			(1,006	)		205,860

Change in cash and cash equivalents	$	(617	)	$	618		$	86,280		$	792		$	85,488

													(in thousands)

Net Cash Flows Provided by (Used in) Operating Activities

Net cash provided by operating activities decreased $1.1 million, to $2.0 million for the year ended December 31, 2011 compared to $3.1 million for the year ended December 31, 2010. For the year ended December 31, 2011, net cash provided by operating activities consisted primarily of net loss of $23.1 million, an increase in other assets of $4.5 million, and a decrease in accounts payable of $1.4 million. Depreciation and amortization represented $11.1 million related to previously purchased equipment. Accrued expenses increased by $17.3 million due to higher spending related primarily to construction in progress purchases. Accounts receivable and other receivables decreased providing cash flows of $1.9 million and $1.2 million, respectively.

Net cash provided by operating activities decreased $0.7 million, to $3.1 million, for the year ended December 31, 2010 compared to $3.8 million for the year ended December 31, 2009. For the year ended December 31, 2010, net cash provided by operating activities consisted primarily of $4.6 million of depreciation and amortization related to previously purchased equipment. Net income of $1.5 million, an increase in accounts payable of $1.2 million, and an increase in accrued expenses of $0.7 million together provided cash totaling $3.4 million.

Net Cash Flows Used in Investing Activities

Net cash used in investing activities increased $118.2 million, to $120.6 million, for the year ended December 31, 2011 compared to $2.4 million for the year ended December 31, 2010. For the year ended December 31, 2011 net cash used in investing activities consisted primarily of purchases of property, plant and equipment of $120.0 million related to hydraulic fracturing and well service equipment additions. Expenditures included the construction of a new district office in Weatherford, Texas and various support equipment and components needed to grow our fleet of hydraulic fracturing and well service equipment.

Net cash used in investing activities decreased $0.8 million, to $2.4 million, for the year ended December 31, 2010 compared to $3.2 million for the year ended December 31, 2009. For the year ended December 31, 2010 net cash used in investing activities consisted primarily of purchases of property, plant and equipment of $2.6 million related to hydraulic fracturing and well service equipment additions.

Net Cash Flows Provided by (Used in) Financing Activities

Net cash provided by financing activities increased $204.9 million to $204.9 million, for the year ended December 31, 2011 compared to $0.0 million for the year ended December 31, 2010. For the year ended December 31, 2011 net cash provided by financing activities consisted primarily of a transaction that closed in November 2011 which provided $241.6 million in net cash proceeds from the issuance of 250,000 units at a price of $990 per unit with each unit consisting of $1,000 principal amount of 13% senior secured notes due 2016 and one warrant to purchase .988235 shares of the Company’s common stock. Shareholders also provided $1.2 million in capital contributions. This was partially offset by cash used in financing activities consisting primarily of net repayments of $29.6 million under our prior senior secured facilities, $14.0 million in debt issuance costs, and $0.2 million to repay owners and affiliates.

Net cash used by financing activities decreased $1.2 million, to $0.0 million, for the year ended December 31, 2010 compared to $1.2 million for the year ended December 31, 2009. For the year ended December 31, 2010 net cash provided by financing activities consisted primarily of $3.5 million in capital contributions, $1.1 million from restricted cash and $0.2 million from owners. This was partially offset by $4.8 million used to repay other long-term debt and $0.1 million to pay distributions.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Business

Company Overview

Each of our turbine-powered hydraulic fracturing units consists primarily of a TFP and various hoses, valves, tanks and other supporting equipment that are typically mounted to 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 hydraulic fracturing “spread” and we refer to all of our spreads together as our hydraulic fracturing “fleet.”

Our current well services customers include Shell, Anadarko Petroleum Corporation, Apache Corporation, Encana Corporation, EOG Resources, Inc. and Denbury Resources Inc. We have entered into MSAs to provide our services to approximately 90 oil and natural gas companies.

In 2011 we entered into a two-year agreement with Shell to provide hydraulic fracturing services. We began providing hydraulic fracturing services to Shell under this agreement in January 2012. Shell has dedicated resources, including technical staff, to work with us to ensure timely completion of hydraulic fracturing equipment that satisfies its technical and safety standards. Please see the section titled “Business—Shell Agreement.”

Our Service Lines

We currently conduct our operations through the following service lines:

Hydraulic Fracturing Services

Our customers utilize our hydraulic fracturing services to enhance the production of oil and natural gas from formations with restricted natural flow of hydrocarbons. The fracturing process consists of pumping a fluid into a perforated well casing or tubing at a sufficient pressure and rate to cause the underground formation to crack, allowing the oil or natural gas to flow more freely. Sand, bauxite, resin-coated sand or ceramic particles, each referred to as a proppant or propping agent, are suspended in the fracturing fluid and prop open the cracks created

by the hydraulic fracturing process in the underground formation. The extremely high pressure required to stimulate wells in many of the regions in which we operate presents a challenging environment for achieving a successfully fractured horizontal well. As a result, an important element of the services we provide to oil and natural gas producers is designing the optimum well completion, which includes determining the proper fluid, proppant and injection specifications to maximize production. Our contracted engineering staff also provides technical evaluation, job design and fluid recommendations to our customers as an integral element of our hydraulic fracturing service.

Our TFPs are powered by remanufactured turbine engines previously used in U.S. military applications. These turbine engines have a reputation for reliability and durability. We believe our TFPs are more cost effective to operate and maintain than conventional diesel-powered equipment. Prior field tests regarding operation of our current TFPs have demonstrated compliance with respect to emissions of nitrogen oxides (“NOx”) and carbon monoxide under the United States Environmental Protection Agency (“EPA”) Clean Air Nonroad Diesel Tier 4 (“Tier 4”) standards that regulate emissions from certain off-road diesel engines. Further emission controls may be required with respect to other emissions regulated by Tier 4 standards, including particulate matter. We expect to conduct further Tier 4 emissions testing in the second quarter of 2012 on certain of our new TFPs.

The following table compares our current turbine-powered pressure pumping equipment against conventional diesel-powered pressure pumping equipment.


	TURBINE-POWERED	CONVENTIONAL DIESEL- POWERED
Multi-Fuel Capability	Natural gas, diesel or biofuel	Diesel or biofuel
Emissions (using diesel)	Lower than typical diesel emissions: Have met Tier 4 standards for NOx and carbon monoxide	Requires catalytic converter to meet Tier 4 standards (reduces HP, additional cost)
HP per trailer	4,500 HP (2 pumps)	2,250 HP (1 pump)
Major Engine Repair	Generally onsite repair or exchange	Generally requires trip to repair shop

We intend to provide hydraulic fracturing and other services to our customers through long-term agreements, such as our agreement with Shell, agreements providing minimum monthly service fees and spot market agreements.

Raw fracturing sand is an essential element of the proppant used in the hydraulic fracturing process. In 2011 we entered into a long-term lease arrangement for two open-pit sand mines, referred to as “wet pit” mines, in Mississippi and Louisiana to secure access to sand for use in our hydraulic fracturing operations as well as to market and sell to other providers of hydraulic fracturing services. The lease expires on September 30, 2041. The base cost for the lease of the Mississippi mine and the Louisiana mine over the lease term is approximately $1.5 million and $2.0 million, respectively. Additionally, we pay royalty fees per ton that vary based on the type of sand, gravel, or clay and other earthen materials extracted. The lease also contains options to purchase the mines in various segments. All of such options expire within the first three years of the lease period.

In connection with the lease agreement for the sand mines, we engaged Terracon to complete a subsurface exploration report that included (i) 12 borings to an average depth of 60 feet at the sand mine consisting of 450 acres in Mississippi (the “Nicholson Mine”) and (ii) 6 borings to an average depth of 60 feet at a portion of the sand mine consisting of 300 acres in Louisiana (the “Hickory Mine”). We also contracted with PropTester, Inc. and Stim-Lab, a division of Core Lab Production Enhancement, to perform analyses in accordance with the American Petroleum Institute Recommended Practice for Testing Sand Used in Hydraulic Fracturing Operations (API RP 56) and in accordance with the International Organization for Standardization 13503-2 on raw and unprocessed sand samples from the mines. Such testing indicated good potential for possible future mining of sand at each mine that is of suitable quality for fracturing. Terracon also conducted preliminary drilling studies based on the borings described above to determine the potential quantity of potential future fracturing sand reserves at each mine site.

Based on the estimates of Terracon, we currently have approximately 26 million tons of sand reserves that fall within the sieve size range traditionally used in fracturing operations. Terracon has estimated that such reserves are “proven” (or “measured”) reserves within the meaning of the SEC’s disclosure rules. Approximately 20 million tons of the reserves are located in the Nicholson Mine and approximately 6 million tons of the reserves are located in the Hickory Mine (each within a mine depth of 60 feet). The estimate for the Hickory Mine is limited to the sand reserves located under approximately 150 acres of our 300-acre Hickory Mine site, which 150 acres is the area with respect to which Terracon’s subsurface exploration report relates. Terracon’s report does not include data for the remainder of the Hickory Mine, though management expects additional reserves in economically producible quantities are located under the remaining acreage, which has been subject to prior exploitation. However, estimates of our sand reserves are dependent on a number of factors, and actual production from identified sand deposit areas or properties and revenues and expenditures associated with our mining operations may vary materially from these estimates. See “Risk Factors—Risks Related to Our Business—Inaccuracies in our estimates of sand reserves could result in lower than expected revenues and higher than expected costs.”

Prior to our lease, the mines had been operated by other operators that primarily extracted aggregate used for construction materials. Since acquiring the lease we have entered into an agreement with Alliance Consulting Group, an affiliate and the designated operator of the mines, to build and operate a wet and dry processing plant and will perform the dredging of our mines and the processing and transportation of the materials from our mines. Under that agreement we have begun to renovate and upgrade our production capabilities on the Hickory Mine to enable it to produce multiple products through various wet processing methods, including washing and screening. We plan to similarly develop the Nicholson Mine in the future. Once we have processed dredged material on site, certain types of sand and aggregate will be marketed to other consumers. Alliance will transport our fracturing sand from our site to a dry processing facility for further processing. We will use this further processed sand to support a portion of our own facturing sand needs as well as demand from other consumers of facturing sand. The dredge used for our mines is operated with diesel fuel and our onsite processing plant will utilize electric power from our local utility.

We will pay Alliance $29 per ton for these services and as of June 8, 2012 we had prepaid Alliance $4 million which will offset future costs. See the section titled, “Business—Alliance Consulting Group Agreement.” We project that the annual raw fracturing sand output will be approximately one million tons. We created a wholly owned subsidiary, Proppant One, Inc., to market the sand from these mines. We believe our sand operations will provide a reliable source of difficult-to-obtain raw fracturing sand. See “Risk Factors—Risks Relating to Our Business—Delays in deliveries of key raw materials or increases in the cost of key raw materials could harm our business, results of operations and financial condition.”

We have also made arrangements to acquire 300,000 tons of sand annually for four years to partially meet our hydraulic fracturing service obligations pursuant to the Shell agreement and other future arrangements. See the section titled “Business—Sand Purchase Agreement.”

Well Services

Our well services include (i) cementing, (ii) coiled tubing, (iii) pressure pumping, (iv) acidizing and (v) other pumping services. This suite of well services complements our turbine-powered hydraulic fracturing services while providing stable cash flow and an additional source of growth.

The following table summarizes our well services fleet in service as of December 31, 2011.


SERVICE	UNITS
Cementing		3
Coiled Tubing		4
Pressure Pumping		5
Acidizing		10
Other Pumping Services		6

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Cementing involves the use of pressure pumping equipment to deliver a slurry of liquid cement that is pumped down a well between the casing and the borehole to isolate fluid zones and to minimize potential damage to hydrocarbon bearing and surrounding formations. In addition, the cement provides structural integrity for the casing by securing it to the earth. Cementing is also done when recompleting wells, where one zone is plugged and another is opened.

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Coiled Tubing involves the insertion of a flexible steel pipe into wells to perform various well servicing operations. Coiled tubing typically has a diameter of less than three inches and is manufactured in continuous lengths of thousands of feet. Due to its small diameter, coiled tubing can be inserted into existing production tubing and used to perform a variety of services to enhance the flow of oil or natural gas without using a larger, more costly workover rig. The principal advantages of using coiled tubing in a workover include the ability to (i) continue production from the well without interruption, (ii) move continuous coiled tubing in and out of a well significantly faster than conventional pipe, (iii) direct fluids into a wellbore with more precision, (iv) provide a source of energy to power a down-hole motor or manipulate down-hole tools and (v) enhance access to remote fields due to the smaller size and mobility of a coiled tubing unit.

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Pressure Pumping involves the use of pressure pumping equipment for well injection, cased-hole testing, workover pumping, mud displacement and wireline pumpdowns.

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Acidizing involves the injection of highly reactive, low pH solutions (such as hydrochloric acid) into the area where hydrocarbons enter the wellbore. Acidizing is the most common means of reducing near-wellbore damage, as it dissolves and dilutes contaminants that have accumulated and may restrict the flow of hydrocarbons from a reservoir toward the wellbore, thus increasing well productivity.

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Other Pumping Services involve the use of nitrogen, an inert gas, in various pressure pumping operations. When provided as a stand-alone service, nitrogen pumping is used to displace fluids in various oilfield applications.

Industry Overview

The pressure pumping industry provides hydraulic fracturing and other well stimulation services to oil and natural gas companies. Hydraulic fracturing involves pumping a fluid down a perforated 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 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, bauxite, resin-coated sand or ceramic particles.

The two main factors influencing demand for hydraulic fracturing services in North America are (1) the level of horizontal drilling activity by oil and natural gas companies and (2) the fracturing requirements of the well being drilled, including the number of fracturing stages and the type and volume of fluids, chemicals and proppant pumped per stage. When drilling a horizontal well, the operator drills vertically into the formation and “steers” 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 being pumped into the well into distinct portions of the wellbore and surrounding formation.

We believe the primary factors increasing the demand for our services are the following:

Ongoing, Sustained Development of Existing and Emerging Unconventional Resource Basins. Over the past decade, exploration and production (“E&P”) companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including multi-stage hydraulic fracturing. We believe long-term capital for the continued development of these basins will be provided in part by the participation of large, well-capitalized domestic and international oil and natural gas companies that have made and continue to make significant capital

commitments through joint ventures and direct investments in North America’s unconventional basins. We believe that these companies are less likely to materially alter their drilling programs in response to short-term commodity price fluctuations.

Increased Horizontal Drilling and Greater Service Intensity in Unconventional Basins. Because of the correlation between horizontal drilling and the need for hydraulic fracturing, pumping and other related services, we view the horizontal rig count as one indicator of the overall demand for our services. According to Baker Hughes Incorporated, the U.S. horizontal rig count has risen from approximately 335 rigs at the beginning of 2007 to 1,167 rigs as of December 31, 2011, and now represents approximately 58% of the total U.S. rig count. Development of horizontal wells has evolved to feature increasingly longer laterals and more fracturing stages, which has increased the requirement for advanced hydraulic fracturing and stimulation services.

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 and Niobrara Shales. According to Baker Hughes Incorporated, the oil- and liquids-focused rig count increased from a low of 20.9% of 876 total active rigs in June 2009 to 53.4% of 2,007 total active rigs as of December 31, 2011. 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 even if oil prices fall below current prices and drilling activity in these areas will continue to support sustained growth in demand for our services.

Constrained Supply of Hydraulic Fracturing Fleets, Proppants and Other Products. The supply of hydraulic fracturing fleets, proppants, replacement and repair parts and other products has not kept up with the increased demand for such products due primarily to increased drilling in unconventional formations. Moreover, individual fracturing stages have become more intensive, requiring more fluids, chemicals and proppant per stage. As drilling in unconventional formations continues and becomes more intensive, we expect the supply and demand imbalance for hydraulic fracturing fleets, proppants and other products to continue throughout 2012 and into 2013.

Utilization of Hydraulic Fracturing for the Redevelopment of Conventional Fields. Oil and natural gas companies have begun to apply the knowledge gained through the extensive development of unconventional resource plays to their existing conventional basins. Many of the techniques, including hydraulic fracturing, applied in unconventional development, when applied to conventional wells either through workover or recompletion, have the potential to enhance overall production or enable production from previously unproductive horizons and improve overall field economics. As a result, hydraulic fracturing services are increasingly being deployed in more mature, traditionally oil-focused basins like the Permian and the Granite Wash basins.

Our Competitive Strengths

We believe that the following competitive strengths position us well within the oilfield services industry:

Differentiated Turbine-Powered Fracturing Equipment. Our TFPs have multiple benefits over conventional diesel-powered fracturing equipment, including:

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Greater fuel flexibility—our TFPs can operate on natural gas, diesel fuel or biofuel, whereas conventional fracturing equipment can generally operate on only diesel or biofuel. We believe our ability to operate our TFPs with various types of fuels, particularly natural gas, will provide significant value for our customers through, among other things, potential cost savings and ease of permitting.

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Smaller footprint—the Frac Stack Pack^TM configuration, for which we have an exclusive license, allows us to provide two pumps (4,500—5,000 total HP) on a single trailer, whereas conventional configurations allow for only a single diesel-powered pump (1,800—2,500 total HP) on a trailer.

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Lower emissions—our current TFPs, even when running on diesel fuel, produce lower emissions than conventional diesel-powered fracturing equipment and have met the Tier 4 standards for NOx and carbon monoxide gas emissions. If we operate our TFPs on natural gas, emissions will be even lower than when we use diesel as a fuel.

•

Easier major engine repair or replacement—because our turbine engines are much smaller and lighter than conventional diesel engines, we have the option to repair or replace turbine engines onsite, whereas a repair or replacement of a diesel engine generally requires a trip to a repair shop.

Increasing Interest in Turbine Fracturing Pumps. We have entered into a two-year agreement with Shell to provide hydraulic fracturing services to Shell’s onshore U.S. E&P business using our TFPs. Shell has dedicated resources, including technical staff, to assist us with producing equipment that satisfies its technical and safety standards. We began providing hydraulic fracturing services to Shell during the first quarter of 2012. We believe that Shell’s interest and investment in our TFP technology, and its status as a premier E&P company with high standards for its well services providers, will allow our specialized TFPs to more quickly gain acceptance by other customers.

Complementary Well Services. We have been providing a wide range of well services to the oil and natural gas industry for over 40 years. These services include: (i) cementing, (ii) coiled tubing, (iii) pressure pumping, (iv) acidizing and (v) other pumping services. We believe that we have developed a reputation for providing quality and reliable services and that our reputation and existing customer base will benefit us as we expand our hydraulic fracturing services. In addition, we believe that our well services diversify our revenue-generating operations and provide an additional source of cash flow.

Secured Sources of Critical Equipment Components. As of March 31, 2012, we had approximately $64.9 million of components for hydraulic fracturing spreads and well services equipment on order with or had made other arrangements to acquire from multiple reliable vendors. We believe the equipment covered under these orders and approximately $3.6 million to be ordered as of March 31, 2012 will allow us to execute our equipment rollout schedule through 2012. The key components of our hydraulic fracturing spreads on order include the pumps, turbines, gearboxes, electrical and hydraulic assemblies and skids. We believe we have secured access to high quality equipment through our strong supplier relationships and contractual agreements.

Highly Experienced Management Team. Our management team has extensive industry experience. Our Chairman and Chief Executive Officer, Michel B. Moreno, beneficially owns 93.3% of the common stock of the Company. Mr. Moreno is the founder and Chief Executive Officer of Moreno Group, LLC, a global, full-service construction company serving the upstream and downstream oil and gas sectors, co-founder of Dynamic Offshore Resources, LLC, an oil and gas company focused on acquiring and developing producing properties in the Gulf of Mexico, and Chief Executive Officer of Dynamic Industries, LLC, a leading fabricator and related field services provider serving the upstream and downstream oil and gas sectors. Our President, Enrique “Rick” Fontova, has over 31 years of oil and natural gas experience, the last nine of which have been spent in the oilfield services industry following 22 years with Shell Oil Company. Our senior management team has an average of more than 25 years of experience in the energy services industry.

Our Strategy

We plan to build upon our competitive strengths to grow our business through the following strategies:

Expand Our Turbine-Powered Pressure Pumping Fleet. As of June 8, 2012, our fleet has 108,000 HP of turbine-powered high pressure pumping capacity and commitments of $68 million for the purchase of additional equipment. With our current customer commitments and in light of current market conditions, we intend to expend only an approximate $33.2 million for the remainder of 2012 to acquire hydraulic fracturing and well services equipment to add another 46,000 HP of turbine-powered high pressure capacity to our fleet and six coiled tubing units. We now plan to have a fleet with approximately 154,000 HP of turbine-powered high pressure capacity. We do not anticipate adding more horsepower without additional firm customer commitments in the future and we may also consider reconfiguring or selling some portion of the earlier assembled units in the fleet based on customer commitments and our evaluation of the market over the near term.

Capitalize on Growth in Development of Shale and Other Resource Plays. The U.S. Energy Information Administration (the “EIA”), forecasts that production from shale gas sources will account for approximately 47%

of U.S. dry gas production in 2035, up from 16% in 2009. We intend to focus our services on shale development and similar onshore resource basins with long-term development potential and attractive economics. We intend to focus our operations on regions that include the Eagle Ford, Marcellus, Utica, Permian and other basins. We also plan to expand our business to include other unconventional oil and natural gas formations, including the Marcellus Shale and Utica Shale in the Appalachian Basin in Pennsylvania, Ohio and West Virginia, and the Haynesville Shale in northern Louisiana, as we increase our fracturing fleet and enter into new agreements with our customers.

Selective Lease or Sale of Turbine Fracturing Equipment. We have received inquiries from a number of oilfield service companies, including Baker Hughes and subsidiaries of some E&P companies, regarding possible sale or lease arrangements for our TFPs. We may consider entering into selective sale or lease arrangements to generate near-term cash flow and profitability while we continue to build out our hydraulic fracturing operations. We expect that we would enter into such an arrangement only in situations in which we would not have the opportunity to provide such services or if our customer agrees that it will not develop or use turbine fracturing technology other than ours for a reasonable period of time.

Continue to Expand our Existing Service Offerings. We continue to evaluate opportunities to grow our existing well services through acquisitions and organic growth opportunities that complement or expand our existing hydraulic fracturing and well services businesses.

Continued Vertical Integration of our Fracturing Services. We believe that continued vertical integration of our hydraulic fracturing services represents an opportunity to reduce our operating costs and improve our financial performance. We have recently entered into a long-term lease arrangement for two sand mines in Mississippi and Louisiana to secure access to sand, the principal proppant used in hydraulic fracturing, which we also plan to market and sell to other providers of hydraulic fracturing services. We are actively considering various opportunities to implement our vertical integration strategy into other components of the hydraulic fracturing supply chain, including through the opportunistic acquisition of a chemical provider.

Shell Agreement

We entered into an agreement, effective September 2, 2011, with Shell to provide Shell with the exclusive right to use a minimum of two high pressure hydraulic fracturing units, with additional units to be made available at Shell’s option. The first hydraulic fracturing unit was delivered during the first quarter of 2012 and the second is expected to be delivered later that year. Shell prepaid us for the purchase, mobilization, modification and preparation of equipment and services provided under the agreement. We used a portion of the proceeds of the private offering of the 13% notes to repay that prepayment in full. Michel B. Moreno and his spouse provided personal guarantees to secure the performance of our obligations pursuant to the agreement.

The Shell agreement terminates two years after the second high pressure hydraulic fracturing unit completes its first fracturing stage, subject to Shell’s right to terminate at any time with 180 days’ written notice. Shell may, at its sole discretion, deliver up to five one-year extensions. In addition, if a termination for cause event occurs, Shell may terminate the agreement and we must pay Shell $10 million in liquidated damages within 90-days after the date such termination is effective. A termination for cause event includes, but is not limited to, (i) failure to deliver the first or second hydraulic fracturing unit on or before its scheduled delivery date, plus, in each case, a 60-day cure period, (ii) failure to achieve certain performance targets or (iii) failure to achieve certain start-up milestones.

Shell may also terminate upon a change of control. A change of control occurs upon our consolidation or merger, a sale, lease, exchange or other transfer of substantially all our assets, or a combination in which our shareholders immediately before such combination do not hold, directly or indirectly, more than 50% of the voting securities of the combined company, except that no change of control shall have occurred if Michel B. Moreno remains Chairman of the Company and certain other conditions are met. Following a change of control termination, we must pay Shell $100 million in liquidated damages.

The agreement may also be terminated by Shell upon a force majeure event.

Sand Purchase Agreement

Effective October 28, 2011, we have made arrangements to acquire 300,000 tons of northern white sand per year for four years from Great Northern Sand LLC (“GNS”), with monthly deliveries expected to begin in September 2012 and to continue through June 2016. We have agreed to make an aggregate of $15 million of advance payments towards the purchase price of the sand through four equal payments of $3.75 million, the first two of which were paid in November 2011 and February 2012. The last two payments are scheduled for April 2012 and thereafter upon certain conditions being satisfied. Beginning in September 2012, or the first month thereafter in which we receive our first delivery of sand, we will pay GNS a monthly fee per ton of sand delivered.

To the extent we fail to purchase our contracted amount in any given year, we will pay GNS liquidated damages calculated based on a dollar amount per ton we did not order for that year. If we pay liquidated damages during a contract year, we may apply any liquidated damages as a payment towards excess tons ordered in the subsequent year and the contract will be deemed to be extended by the period of time necessary to take delivery of sand in an amount equal in value to the liquidated damages paid. GNS may terminate the agreement by written notice if we (i) fail to make timely payment, (ii) fail to perform any other provision of the agreement (following a 30-day cure period after receipt of written notice from GNS) or (iii) become insolvent or engage in an act that reasonably causes GNS to deem itself insecure.

Alliance Consulting Group Agreement

In January 2012 we entered into an agreement with Alliance Consulting Group, an affiliate, to build and operate a wet and dry processing plant that will perform the mining, processing and transportation of raw fracturing sand from these mines to support a portion of our own fracturing sand needs as well as demand from other consumers of fracturing and other types of sand. We will pay Alliance $29 per ton for these services and as of June 8, 2012 had prepaid Alliance $4 million which will offset future costs. We project that the annual raw fracturing sand output will be approximately one million tons.

Chemrock Technologies Agreement

In February 2012, we entered into an agreement to purchase chemicals from Chemrock Technologies, LLC, a chemical company. The contract calls for preferred pricing and will result in payments that could exceed $50.0 million dollars in 2012. The Company will also purchase chemicals from unrelated vendors.

Customers

Our well service customers include Shell, Anadarko Petroleum Corporation, Apache Corporation, Encana Corporation, EOG Resources, Inc. and Denbury Resources Inc. Our top five customers accounted for approximately 57% and 68% of total revenues for the three months ended March 31, 2012 and 2011, respectively, and approximately 52%, 55% and 38% of our revenues for the years ended December 31, 2011, 2010 and 2009, respectively.

We began providing hydraulic fracturing services in December 2010. Since that time, we have performed hydraulic fracturing services utilizing our TFPs for Republic, Navidad and Roywell and have entered into the Shell agreement to perform such services with our TFPs. We are negotiating with and otherwise pursuing other major independent companies to expand our customer base.

Suppliers

We purchase the materials used in our well services, such as coiled tubing and cementing supplies, from various suppliers. We purchase components for our hydraulic fracturing units from a number of suppliers, including FMC Technologies, Inc., Yantai Jereh Petroleum Equipment & Technologies Co., Ltd., OFM Pumps, Inc. and Dynamic Industries, Inc.

In September 2011 we formed TPT as a joint venture with MTT. TPT purchases the turbine-engines used in our TFPs and assembles the TFPs. Under the joint venture arrangements, we have the exclusive right to purchase turbines and accessory equipment from TPT until October 2016. Our royalty-free perpetual license to use purchased equipment will survive the termination of the exclusivity period. Following the termination of the exclusivity period, we will also have a perpetual right of first offer on all TFPs sold by TPT. Along with the equipment purchase arrangements, we have entered into installation and maintenance agreements with TPT. Under these agreements, TPT provides all labor and professional supervisory and managerial personnel as are required for installation of turbine engines on trailers or into skids and maintains and repairs all turbine-powered equipment, accessory equipment, and all gearboxes and accessory gearboxes that we purchase. Under such agreements, we pay costs plus agreed upon markups to TPT.

Where we currently source materials from a single supplier, we believe that we will be able to make satisfactory alternative arrangements in the event of interruption of supply, except with respect to our agreement to obtain TFPs exclusively from TPT. However, given the limited number of suppliers of certain of our raw materials, we may not always be able to make alternative arrangements should one of our suppliers fail to deliver or timely deliver our materials.

During the year ended December 31, 2011, we purchased 5% or more of our materials or equipment from each of, Dynamic Industries, Inc., Yantai Jereh Petroleum Equipment & Technologies Co., Ltd., FMC Technologies, Inc., Rush Truck Center of Texas, L.P. and Marine Turbine Technologies, L.L.C. During the three months ended March 31, 2012, we purchased 5% or more of our materials and equipment from Advanced Turbine Services, Dynamic Industries, Inc., EBR Services, LLC, FMC Technologies-Fluid Control Division, Supreme Electrical Services, Inc., Turbine Powered Technology, LLC, Keystone Oilfield Fabrication, LLC and SVP Products, Inc.

Equipment

Competition

The competition for our services includes multi-national oilfield service companies as well as regional competitors. Our major multi-national competitors include Halliburton Company, Schlumberger Ltd. and Baker Hughes. Our multi-national competitors typically have a more diverse product and service offerings than we do. In addition, we compete against a number of smaller, regional operators, which offer products and services, other than products and services related to our TFPs, similar to the products and services we offer.

Seasonality

Our results of operations have not historically reflected any material seasonal tendencies, and we currently do not believe that seasonal fluctuations will have a material impact on us in the foreseeable future.

Properties

Our primary corporate office is located at 4023 Ambassador Caffery Parkway, Suite 200, Lafayette, LA 70503. We currently lease the corporate office under a lease agreement that expires on May 31, 2014. We also own or lease several other facilities. Our leases, other than our lease with respect to sand mines, generally have terms of one to three years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. Other than our sand mine facilities, we do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. As of March 31, 2012, we maintained the following properties in addition to our primary corporate office:


LOCATION	USE OF FACILITY	EXPIRATION OF LEASE OR OWN
4700 NE Evangeline Thruway Carencro, LA 70520	District office—storing and repairing equipment and general office purposes	December 14, 2012

11441 State Hwy 43 South Marshall, TX 75670	District office—storing and repairing equipment and general office purposes	Own

350 Dennis Road Weatherford, TX 76087	District office—storing and repairing equipment and general office purposes	Own

301 Duhon Rd Lafayette, LA 70506	Storing and repairing equipment and general office purposes	July 31, 2013

1600 Stout St, Ste 1370 Denver, CO 80202	Sales office	October 15, 2014

3700 Ambassador Caffery, Unit 2045, Lafayette, LA 70503	Storage unit	Month-to-month

301 Commerce St, 21st Floor Fort Worth, TX 76102	Vacant office space	September 30, 2012

3116 Jackson Landing Rd. Nicholson, MS 39463	Sand mine	September 30, 2041 lease expiration, subject to limited option to purchase

69761 LA Industries Pit Rd. Pearl River, LA 70452	Sand mine	September 30, 2041 lease expiration, subject to limited option to purchase

Risk Management and Insurance

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

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personal injury or loss of life;

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

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suspension of operations.

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

Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.

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

We maintain insurance coverage of types and amounts that we believe to be customary in the industry including workers’ compensation, commercial general liability, business auto, property, umbrella liability and excess liability insurance all subject to certain limitations, deductibles and caps. As discussed below, our MSAs provide, among other things, that our customers generally assume liability for underground pollution and pollution emanating from the wellbore as a result of an explosion, fire or blowout. We retain the risk for any liability not indemnified by our customers in excess of our insurance coverage. Our insurance coverage may be inadequate to cover our liabilities and our customers may be unable or unwilling to fulfill their indemnity obligations to us under the MSAs. In addition, we may not be able to maintain adequate insurance in the future at affordable rates.

We enter into MSAs with each of our customers. Our MSAs delineate our and our customer’s respective indemnification obligations with respect to the services we provide. With respect to our hydraulic fracturing services, our MSAs typically provide for knock-for-knock indemnification for all losses, which means that we and our customers assume liability for damages to our respective personnel and property without regard to fault. For catastrophic losses, our MSAs generally include industry-standard carve-outs from the knock-for-knock indemnities, pursuant to which our customers (typically the exploration and production company) assume liability for (i) damage to the hole, including the cost to re-drill; (ii) damage to the formation, underground strata and the reservoir; (iii) damages or claims arising from loss of control of a well or a blowout; and (iv) allegations of subsurface trespass.

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

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

Intellectual Property Rights

We currently have no foreign or domestic patents or pending patent applications but protect our unpatented proprietary technology under a combination of trade secret laws and third-party nondisclosure and assignment agreements. In addition, we currently have an exclusive license from TPT under its technology relating to the Frac Stack Pack™ to make and commercialize our TFPs and use the Frac Stack Pack™ trademark. Ted McIntyre II, filed a non-provisional patent application with the United States Patent and Trademark Office on August 25, 2011 claiming certain aspects of the technology which he subsequently transferred to TPT. Mr. McIntyre is currently the Manager and Chief Executive Officer of TPT. Please see the section titled “Certain Relationships and Related Person Transactions—Joint Venture” for additional information.

Legal Proceedings

We are from time to time a party to various claims and legal proceedings related to our business. We maintain insurance coverage to reduce financial risk associated with certain of these claims and proceedings. It is not possible to predict the outcome of these claims and proceedings. However there are no current material claims or legal proceedings pending against us that, in the opinion of our management, are likely to have a material adverse effect on our business, financial condition, results of operations or liquidity.

Environmental Matters

Environmental laws and regulations may, among other things, require the acquisition of permits to conduct our operations; restrict the amounts and types of substances that may be released into the environment or the way we use, handle or dispose of our wastes in connection with our operations; cause us to incur significant capital expenditures to install pollution control or safety-related equipment at our operating facilities; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose substantial liabilities on us for pollution resulting from our operations. Environmental laws and regulations have changed in the past, and they are likely to change in the future. If existing regulatory requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.

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issuance of material administrative, civil and criminal penalties;

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modification, denial or revocation of permits or other authorizations;

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imposition of limitations on our operations; and

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performance of site investigatory, remedial or other corrective actions.

Climate Change

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has begun to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating GHG emissions under the

CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which, known as the “Tailoring Rule,” will require that certain large stationary sources obtain permits for their emissions of GHGs. The EPA has also adopted rules requiring the reporting of GHG emissions from certain large GHG emission sources, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

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

Employees

As of March 31, 2012, our workforce consisted of 299 employees, including 2 part-time employees. We are not a party to any collective bargaining agreements. We consider our relations with our employees to be good, and we have not had any major labor-related issues such as business interruptions during the past several years.

Management

Directors and Executive Officers


NAME	AGE	TITLE
Michel B. Moreno	43	Chairman and Chief Executive Officer

Enrique “Rick” Fontova	53	President and Director

Earl J. Blackwell	69	Chief Financial Officer

Charlie Kilgore	52	Director

Mark Knight	53	Director

Set forth below is the description of the backgrounds of our directors and executive officers.

Michel B. Moreno has been a beneficial equity holder and an advisor to the Company since June 2006. Upon our corporate reorganization in October 2011, Mr. Moreno became the Chairman of our Board of Directors and our Chief Executive Officer. Mr. Moreno beneficially owns 93.3% of the common stock of the Company. He is also the founder and Chief Executive Officer of Moreno Group, LLC, a global, full-service construction company serving the upstream and downstream oil and gas sectors, co-founder of Dynamic Offshore Resources, LLC, an oil and gas company focused on acquiring and developing producing properties in the Gulf of Mexico, and Chief Executive Officer of Dynamic Industries, LLC, a leading fabricator and related field services provider serving the upstream and downstream oil and gas sectors. He also founded and grew several companies until their sale including: Moreno and Associates, a safety consulting company for the offshore oil and gas industry, Pure Water Solutions, an equipment rental company for the offshore oil and gas industry, and Dynamic Cranes, an offshore crane rental company.

Enrique “Rick” Fontova was our Chief Executive Officer from May 2011 until our corporate reorganization in October 2011, at which time Mr. Fontova became our President and a Director. Mr. Fontova has over 31 years of oil and natural gas experience, the last nine of which have been spent in the oilfield services industry following 22 years with Shell Oil Company. Mr. Fontova joined Moreno Group, LLC as president of Dynamic Power, LLC in February of 2009, and previously served as Senior Vice President of International Sales and Operations of Eventure Global Technology, which provides solid expandable casing services.

Earl J. Blackwell has been our Chief Financial Officer since 2009. He was previously involved with the Company through his position as Managing Director of Moody Moreno & Rucks L.L.C., a private equity firm that invests in companies in the environmental, energy, communications, and oil and gas industries and which invested in a predecessor of the Company in 2005. Mr. Blackwell has extensive experience as a Certified Public Accountant for 15 years including as Senior Partner at Broadhurst, Blackwell & Gardes, a Certified Public Accounting Firm. He also has 25 years of experience as Chief Financial Officer or Chief Operating Officer in several industrial waste and property development companies.

Charlie Kilgore became a director upon our corporate reorganization in October 2011. Mr. Kilgore founded and currently serves as Chief Executive Officer of Kilgore Marine Services, an industrial marine transportation company servicing the Gulf of Mexico. He has 26 years of experience in operating marine transportation service companies, and previously worked as a Drilling Engineer for Conoco Inc.

Mark Knight became a director upon our corporate reorganization in October 2011. He currently serves as President and Chief Executive Officer of Knight Oil Tools Inc., which provides rental tools, fishing services, well services, saw services, and manufacturing packages to the oil and gas industry. Mr. Knight is also a board member for the Boys and Girls Club of Acadiana, Acadiana Symphony, Evangeline Area Council of the Boy Scouts of America, Our Lady of Fatima School Board, and currently serves on the St. Thomas More Foundation Board.

Board of Directors

Our Board of Directors is currently comprised of Michel B. Moreno, Enrique “Rick” Fontova, Charlie Kilgore and Mark Knight. Each of our directors is elected or appointed to hold office until the next annual meeting of stockholders and until his successor has been elected and qualified.

Executive Compensation

Summary Compensation Table

The following table sets forth summary information concerning the compensation awarded to, paid to or earned by each of our named executive officers during the fiscal year ended December 31, 2011.


Name and Principal Position	Year		Salary ($)		Bonus ($)(1)		All Other Compensation ($)			Total
Michel B. Moreno		2011		303,066		355,149		—		$	658,215
Chairman and Chief Executive Officer(2)

John M. Eglé		2011		306,488		—	$	106,555	(4)	$	413,043
Market Advisor(3)

Enrique Fontova		2011		186,984		200,000	$	7,200	(6)	$	394,184
President and Director(5)

Earl Blackwell		2011		205,323		48,125		—		$	253,448
Chief Financial Officer

Virgil Vincent		2011		129,626		75,000	$	7,200	(8)	$	211,826
Vice President, Commercialization(7)

(1)

Amounts shown represent the payment of discretionary annual bonuses for 2011. For a complete description of the annual bonuses for 2011, including how actual payouts were determined, see the “Narrative to Disclosure to Summary Compensation Table—Annual Bonuses” section below. For Mr. Vincent, the amount shown includes a signing bonus in the amount of $50,000 paid to Mr. Vincent pursuant to the terms of his offer letter.

(2)

Mr. Moreno became our Chairman of the Board and Chief Executive Officer, effective October 6, 2011, in connection with our corporate reorganization. The amount shown in the “Salary” column for Mr. Moreno represents his base salary earned for the period from his date of hire on May 1, 2011 through December 31, 2011.

(3)	Mr. Eglé ceased to serve as our Chief Executive Officer and became our Market Advisor, effective May 1, 2011. For the period from January 15, 2009 through May 1, 2011, Mr. Eglé served as our Chief Executive Officer.

(4)

Amount shown represents the portion of the aggregate group health and disability insurance premiums that were paid by the Company on behalf of Mr. Eglé in excess of the premiums generally paid by employees during 2011 totaling $4,422; a monthly automobile allowance of $1,300 paid to Mr. Eglé during 2011 totaling $15,600, pursuant to the terms of his employment agreement; and the accelerated payment of $86,533, including $81,333 of base salary and $5,200 of automobile allowance, otherwise payable to Mr. Eglé during the period of his employment from January 1, 2012 through April 30, 2012 pursuant to the terms of his employment agreement.

(5)

Mr. Fontova served as our Chief Executive Officer effective from May 16, 2011 until October 6, 2011, at which time, he became our President and Director, effective October 6, 2011, in connection with our corporate reorganization. The amount shown in the “Salary” column for Mr. Fontova represents his base salary earned for the period from his date of hire on May 16, 2011 through December 31, 2011.

(6)	Amount shown represents a monthly automobile allowance in the amount of $1,200 paid to Mr. Fontova during the six-month period in 2011.

(7)	Mr. Vincent became our Vice President, Commercialization, effective June 1, 2011. The amount shown in the “Salary” column for Mr. Vincent represents his base salary earned for the period from his date of hire on June 1, 2011 through December 31, 2011.

(8)	Amount shown represents a monthly automobile allowance in the amount of $1,200 paid to Mr. Vincent during the six-month period in 2011.

Narrative Disclosure to Summary Compensation Table

Employment Agreements

We have entered into employment agreements with each of our named executive officers in connection with the executive’s employment with us. The principal elements of these employment agreements are summarized below.

Messrs. Moreno, Fontova and Blackwell

Effective as of October 6, 2011, we entered into employment agreements with each of Messrs. Moreno and Fontova that provide for Mr. Moreno’s employment as our Chief Executive Officer and Mr. Fontova’s employment as our President, respectively. Effective as of May 1, 2011, we entered into an employment with Mr. Blackwell that provides for his employment as our Chief Financial Officer. The employment agreements with Messrs. Moreno and Fontova have a term of four years beginning on October 6, 2011 and ending on October 6, 2015, and the employment agreement with Mr. Blackwell has a term of three years beginning on November 1, 2011 and ending on November 1, 2014, in each case, subject to automatic one-year extensions thereafter, unless either party provides at least 30 days’ prior notice of non-renewal.

As of December 31, 2011, the annual base salaries of the executives pursuant to their employment agreements were $475,000 for Mr. Moreno, $375,000 for Mr. Fontova and $275,000 for Mr. Blackwell, in each case, subject to annual review by the Company. Mr. Fontova’s annual base salary was increased to $375,000 from $100,000 effective July 16, 2011. Mr. Blackwell’s annual base salary was increased to $275,00 from $154,500 effective May 1, 2011. In addition to annual base salary, Messrs. Moreno and Fontova are eligible for an annual bonus of 50% to 100% of their respective annual base salaries, and Mr. Blackwell is eligible for an annual bonus without reference to a specified percentage of annual base salary. During their employment, Messrs. Moreno, Fontova and Blackwell are eligible to receive the same benefits generally made available our employees, as well as four weeks of paid vacation time each year.

The employment agreements with Messrs. Moreno, Fontova and Blackwell provide that in the event that the executive’s employment is terminated by the Company either (i) upon our determination to cease the Company’s business operations or (ii) upon the sale of a majority interest in the stock or ownership interests of the Company, or all or substantially all of the Company’s assets, in each case, at our election, the executive will be entitled to receive a cash payment equivalent to six months of the executive’s base salary payable within seven business days after the date of termination. If the executive’s employment is terminated due to the expiration of the then-current term of the employment agreement, the executive will be entitled to payment of any target annual bonus payable within seven business days after the date of termination. If the executive’s employment is terminated by reason of his death or disability, he will be entitled to receive a cash payment equivalent to one year’s base salary, in the case of Messrs. Moreno and Fontova, or six months’ base salary, in the case of Mr. Blackwell, of the executive’s base salary payable within seven business days after the date of termination.

The employment agreements with Messrs. Moreno, Fontova and Blackwell contain certain non-competition and non-solicitation covenants that apply during the term of the employment agreements and for a two-year period thereafter and a confidentiality covenant that applies indefinitely.

Mr. Eglé

2009 Employment Agreement

Effective as of January 15, 2009, we entered into an amended and restated employment agreement with Mr. Eglé that provided for his employment as our Manager and Chief Executive Officer. Mr. Eglé’s 2009 employment agreement had a term of three years beginning on January 15, 2009 and ending on January 14, 2012, unless the parties mutually agreed to extend the term.

Pursuant to his 2009 employment agreement, Mr. Eglé’s annual base salary was $244,000, subject to annual review by the Company. In addition to annual base salary, Mr. Eglé was eligible for discretionary bonuses based on performance and established goals for Mr. Eglé and the Company. The 2009 employment agreement provided that Mr. Eglé was eligible to participate in the Company’s employee benefit plans and receive four weeks of paid vacation time each year. In addition, the Company was obligated to pay 100% of his group health and disability insurance premiums and provide him with a monthly automobile allowance of $1,300.

Mr. Eglé’s 2009 employment agreement provided that if Mr. Eglé’s employment was terminated due to: (i) his removal as the manager of the Company without cause under the Company’s operating agreement, he would receive payment of his annual base salary otherwise due for the remaining term of the employment agreement, (ii) his death or the termination of his status, or any entity that he owns or controls, as a limited liability company member of the Company, or the withdrawal of Mr. Eglé or such other entity a member of the Company as provided under the Company’s operating agreement, he would receive payment of an additional one month of annual base salary, or (iii) his disability, he would receive payment of an additional two months of annual base salary less any disability insurance benefits received by him.

Mr. Eglé’s 2009 employment agreement contained certain non-competition and non-solicitation covenants that applied during the term of the agreement and for a two-year period thereafter and a confidentiality covenant that applied indefinitely.

2011 Employment Agreement

Effective as of May 1, 2011, we entered into an amended and restated employment agreement with Mr. Eglé that provides for his employment as our Market Advisor, or Special Assistant to Mr. Moreno, as he ceased to serve as our Manager and Chief Executive Officer as of such date. Mr. Eglé’s 2011 employment agreement amends and restates in its entirety his 2009 employment agreement. Mr. Eglé’s 2011 employment agreement has a term of one year beginning on May 1, 2011 and ending on April 30, 2012, subject to an additional term of one-year conditioned upon Mr. Eglé booking international sales in excess of $1,000,000 during the first year of the employment agreement, unless the parties otherwise mutually agree to extend the term.

As of December 31, 2011, Mr. Eglé’s annual base salary pursuant to his 2011 employment agreements was $244,000, subject to annual review by Mr. Moreno. In addition to annual base salary, Mr. Eglé is entitled to receive 3% to 5% of revenue directly generated from international sales by him for the Company, with such percentage to be jointly determined by Mr. Eglé and the Company. Mr. Eglé was not paid any such sales revenue for 2011. The 2011 employment agreement provides that Mr. Eglé may participate in the Company’s employee benefit plans and receive four weeks of paid vacation time each year. In addition, the Company is obligated to pay 100% of his group health and disability insurance premiums and provide him with a monthly automobile allowance of $1,300.

Mr. Eglé’s 2011 employment agreement provides that in the event that Mr. Eglé’s employment is terminated by the Company without “cause” (as defined in the employment agreement), Mr. Eglé will be entitled to receive payment of his annual base salary otherwise due for the remaining term of the employment agreement. If his employment is terminated by reason of his death, Mr. Eglé will receive payment of an additional one month of annual base salary. If his employment is terminated by reason of his disability, Mr. Eglé will receive payment of an additional two months of annual base salary less any disability insurance benefits received by him.

In December 2011, we agreed to provide Mr. Eglé with the accelerated payment of $86,533, including $81,333 of base salary and $5,200 of automobile allowance, otherwise payable to Mr. Eglé during the period of his employment from January 1, 2012 through April 30, 2012 pursuant to the terms of his 2011 employment agreement, which was paid on December 16, 2011.

Mr. Eglé’s 2011 employment agreement contains certain non-competition and non-solicitation covenants that apply during the term of the agreement and for a two-year period thereafter and a confidentiality covenant that applies indefinitely.

Mr. Vincent

Effective as of June 1, 2011, we entered into an employment offer letter with Mr. Vincent that provides for his employment as our Vice President of Commercialization. Mr. Vincent’s offer letter provides that his employment with us is “at-will” and either party may terminate his employment at any time and for any reason.

As of December 31, 2011, Mr. Vincent’s annual base salary pursuant to his offer letter was $225,000, subject to periodic review by the Company. In addition to annual base salary, Mr. Vincent received a $50,000 signing bonus paid in June 2011. Mr. Vincent is also eligible for an annual bonus with a target of 35% of annual base salary. Mr. Vincent is eligible to participate in the Company’s long term value plan upon adoption of the plan by the Company. During his employment, Mr. Vincent is eligible to participate in the Company’s employee benefit plans.

Mr. Vincent’s offer letter states that the parties agree that a severance and change in control agreement would be implemented for Mr. Vincent during 2011; however, no such agreement was implemented during 2011. The parties expect to implement an agreement in 2012.

Mr. Vincent’s offer letter contains certain non-competition and non-solicitation covenants that apply during the term of his employment.

Perquisites and other Personal Benefits

We provide our named executive officers with limited perquisites and personal benefits, which serve as an important recruiting and retention tool. Each of Messrs. Fontova and Vincent is entitled to a monthly automobile allowance of $1,200, and Mr. Eglé is entitled to a monthly automobile allowance of $1,300. In addition, we pay 100% of Mr. Eglé’s group health and disability insurance premiums pursuant to the terms of his employment agreement.

Annual Bonus

We do not have a formal bonus plan, but we have historically paid discretionary cash bonuses to our named executive officers as we believe annual cash bonuses motivate employees. While the employment agreements with each of Messrs. Moreno and Fontova and the offer letter with Mr. Vincent provide for a target annual bonus expressed as a percentage of annual base salary, the employment agreements with Mr. Blackwell does not refer to a specified percentage of annual base salary, and the actual bonus amount for each executive for 2011 was determined by Mr. Moreno as Chief Executive Officer based on an evaluation of the Company’s performance, the executive’s contributions to the Company’s performance and the executive’s individual performance.

In determining the annual bonus awarded to our named executive officers for 2011, Mr. Moreno as Chief Executive Officer considered the progress made toward the Company’s achievement of its business plan, with particular focus on operating goals related to the building of the frac business and the overall changeover from Hub City Industries to Green Field Energy Services, the executive’s contributions to the Company’s achievement of such business plan, and certain individual performance factors, including leadership related to the significant changes made in the business. All of these factors were assessed on a subjective basis with no single factor being determinative.

Based on this evaluation, Mr. Moreno as Chief Executive Officer determined to pay our named executive officers the following annual bonuses: Mr. Moreno, $355,149; Mr. Fontova, $200,000; Mr. Blackwell, $48,125; and Mr. Vincent, $25,000. Mr. Eglé did not receive an annual bonus for 2011 because he became eligible to receive a percentage of revenue directly generated from international sales by him for the Company, as jointly determined by him and the Company, pursuant to his 2011 employment agreement. Mr. Eglé did not receive any revenue-based sales compensation or other bonus or incentive compensation for 2011.

Outstanding Equity Awards at Fiscal Year-End

None of our named executive officers held any outstanding equity awards as of December 31, 2011 as we have not historically granted equity award compensation to our named executive officers.

Retirement Benefits

We currently maintain a 401(k) plan pursuant to which employees, including our named executive officers, may contribute a portion of their eligible compensation, subject to the maximum allowed under the Internal Revenue Code. We did not provide an employer matching contribution under the plan during 2011.

Additional Narrative Disclosure

For a description of the material terms of the severance provisions of the employment agreements with our named executive officers, please see the “Narrative to Disclosure to Summary Compensation Table—Employment Agreements” section above. Our named executive officers were not entitled to any change in control protections during 2011.

Director Compensation

We did not pay or award any compensation to our non-employee directors during 2011.

Director Independence

Two of the four members of our Board of Directors are non-management directors. We believe such non-management directors are “independent” as defined in the currently applicable listing standards of the New York Stock Exchange. Prior to the effective date of this registration statement, our Board of Directors will affirmatively determine whether or not such non-management directors are independent under such standards.

Audit Committee of the Board

We do not have a separately-designated standing audit committee. The entire Board of Directors performs the functions of an audit committee, but no written charter governs the actions of the Board when performing the functions that would generally be performed by an audit committee. The Board of Directors approves the selection of our independent accountants and meets and interacts with the independent accountants to discuss issues related to financial reporting. In addition, the Board of Directors reviews the scope and results of the audit with the independent accountants, reviews with management and the independent accountants our annual operating results, considers the adequacy of our internal accounting procedures and considers other auditing and accounting matters including fees to be paid to the independent auditor and the performance of the independent auditor.

Code of Ethics

Due to our small size and the limited number of persons comprising our management, we have not adopted a generally applicable code of ethics. However, under our employment agreements with our Chief Executive Officer, our President, and our Chief Financial Officer, such officers have agreed to a code of ethics and behavior consistent with our corporate philosophy.

Beneficial Ownership

The following table presents the number and percentage of shares of common stock of the Company that are beneficially owned as of June 1, 2012 by (i) each person or group that is known to us to be the beneficial owner of more than 5% of such common stock, (ii) each of our named executive officers and directors and (iii) our executive officers and directors as a group.

The amounts and percentages of common stock beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has the right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed to be a beneficial owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which he or she has no economic interest. To our knowledge, each of the security holders listed below has sole voting and investment power as to the securities shown unless otherwise noted and subject to community property laws where applicable.


NAME(1)	NUMBER OF SHARES OF COMMON STOCK		PERCENTAGE OWNERSHIP
Greater than 5% holders:
MMH		1,244,460		88.9	%
MMR		155,540		11.1	%
Named Executive Officers and Directors:
Michel B. Moreno		1,306,620		93.3	%
Enrique “Rick” Fontova		—		*
Earl J. Blackwell		—		*
Charlie Kilgore		—		*
Mark Knight		—		*
All executive officers and directors as a group (6 persons)		1,306,620		93.3	%

*	Indicates less than 1%.

⁽¹⁾	Unless otherwise indicated, the business address of each of the holders is: c/o Green Field Energy Services, Inc., 4023 Ambassador Caffery Parkway, Suite 200, Lafayette, LA 70503.

Selling Shareholders

Selling shareholders may use this prospectus to offer and sell the common stock. See “Determination of Offering Price and Plan of Distribution.” The registration statement of which this prospectus forms a part has been filed pursuant to Rule 415 under the Securities Act to afford the holders of the common stock the opportunity to sell their common stock in a public transaction rather than pursuant to an exemption from the registration and prospectus delivery requirements of the Securities Act. In order to avail itself of that opportunity, a holder must notify the Company in writing of its intention to sell common stock and request that the Company file a supplement to this prospectus or an amendment to the registration statement, if required, identifying such holder as a selling shareholder and disclosing such other information concerning the selling shareholder and the common stock to be sold as may then be required by the Securities Act and the rules of the SEC. No offer or sale pursuant to this prospectus may be made by any holder until such a request has been made and until any such supplement has been filed or any such amendment has become effective.

Determination of Offering Price and Plan of Distribution

The selling shareholders and their transferees of any sort, including pledgees or secured parties of such selling shareholders in case of default, may from time to time sell all or any of their shares of common stock on or through the facilities of any stock exchange, market or trading facility on which the shares are traded or quoted. These sales may be at fixed or negotiated prices. The principal factors to be considered by a selling shareholder in determining the price include the following:

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the information included in this prospectus and otherwise available to the selling shareholder;

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the history of and prospects for our business and our past and present operations;

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the history and prospects for the industry in which we compete;

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our past and present earnings and current financial position;

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the market for securities of companies in businesses similar to ours; and

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the general condition of the securities market.

There were two holders of record of our common stock as of June 1, 2012, the most recent practicable date before the filing of this document.

The selling shareholders may use a variety of methods when selling our common stock, including ordinary brokerage transactions and transactions where the broker-dealer solicits purchasers, block trades in which the broker-dealer may attempt to sell as an agent or resell as a principal, including for its own account, an exchange distribution in accordance with the rules of any such exchange, privately negotiated transactions or any other method permitted by law. The selling shareholders may also sell shares under Rule 144 under the Securities Act, if available, or in other private resales, rather than under this prospectus.

If the selling shareholder effects the sale or transfer of its common stock through a broker-dealer, such broker-dealer may receive compensation in the form of discounts, concessions or commissions from the selling shareholder or the purchasers of common stock for whom such broker-dealer may act as agent or to whom they sell as principal or both (which compensation is not expected to exceed what is customary in the types of transactions involved). The selling shareholder and any broker-dealer that acts in connection with the sale or transfer of the common stock may be deemed to be “underwriters” within the meaning of Securities Act. In such event, any commissions received by such broker-dealer or agent and any profits on the resale of the shares of common stock purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act.

Upon our being notified in writing by a selling shareholder that any material arrangement has been entered into with any broker-dealer for the sale of common stock, a supplement to this prospectus will be filed to the extent applicable that sets forth the amount of common stock to be sold and the terms of the sale, any plan of distribution, the names of any underwriters, brokers, dealers or agents, any discounts, commissions, concessions or other items constituting compensation from the selling shareholders or any other information as may be required under the Securities Act.

We are required to pay all fees and expenses incident to the registration of the common stock. We have agreed to indemnify the selling shareholders against certain losses, claims, damages and liabilities, including liabilities under the Securities Act.

Certain Relationships and Related Person Transactions

Our parent companies

The list below shows our parent companies:

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MMH controls Green Field Energy Services, Inc. through its 88.9% ownership of our common stock; and

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Michel B. Moreno controls MMH through his 50% ownership of the limited liability company interests of MMH.

Joint Venture

In September 2011 we formed TPT in conjunction with MTT. MTT is owned and controlled by Ted McIntyre, II, the developer of the turbine-powered technology underlying TFPs. Under the joint venture arrangements, Mr. McIntyre, MTT and its affiliates transferred all rights in the technology to TPT.

Under the operating agreement of TPT, we and MTT each have a 50% ownership interest in TPT. Mr. McIntyre is the Manager and Chief Executive Officer of TPT and has the right of management and control of TPT’s day to day affairs and business and of the maintenance of TPT’s property, subject to fiduciary duties and certain other limitations as provided in the operating agreement (which include, among other things, limitations on TPT’s management under Section 5.13.2 (“Limitations on Management”) of its operating agreement, to, without the consent of us and MTT, (a) sell, exchange, lease, mortgage, pledge or transfer all, substantially all, or any material portion of TPT’s assets; (b) undertake any other action, activity, obligation, or commitment by or on behalf of TPT that would require, involve, or result, either individually or annually in the aggregate: (i) in an expenditure or outlay of funds by TPT, or a commitment or obligation of TPT to pay, turnover, transfer, subject to any encumbrance, or otherwise dispose of, cash in excess of $1.0 million, or assets or other property with a value of more than $1.0 million; or (ii) in a commitment or obligation by TPT to otherwise become liable or obligated for any other obligations in excess of $1.0 million; or (iii) borrowing funds, executing promissory notes or loan agreements or incurring any indebtedness in excess of $250,000; (c) merge or consolidate TPT with or into any other entity; (d) change the character of TPT’s business; (e) allow TPT to act as endorser, guarantor, or surety for the debt or obligations of any other person; (f) initiate any bankruptcy proceedings by or on behalf of TPT; (g) dissolve TPT; (h) commission any act that would make it impossible for TPT to carry on its ordinary business; and (i) cause or allow TPT to guarantee payment of the promissory notes, mortgage notes, collateral mortgage notes, hand notes, or any other indebtedness or obligations of any person, firm, corporation, partnership or other entity to any bank, savings and loan association or any other creditor or other entity whatsoever). Mr. McIntyre can be removed only by a vote of the members holding 51% of the ownership interests. In addition, under the operating agreement if (i) 50% or more of our ownership interests becomes owned by a person or entity that is not an affiliate or (ii) there occurs any other change in our ownership that results in a change of control, we shall no longer have any voting rights in TPT and may have our ownership interests purchased at the option of the other members at such time; provided, that our ownership interests in TPT will not be subject to such change of control provision for so long as any 13% notes are outstanding. The operating agreement further provides that, for the avoidance of doubt, if a “Default” occurs under the terms of and as defined in the indenture governing the 13% notes, the collateral agent acting on behalf of the holders of the 13% notes (or any designees of such agent), will be admitted as and will become a member of TPT in place of the Company without any further vote or any other type of approval by the member or members at such time.

We will also have the exclusive right to purchase turbines and accessory equipment from TPT until October 2016. Our royalty-free perpetual license to use purchased equipment will survive the termination of the exclusivity period. Following the termination of the exclusivity period, we will also have a perpetual right of first offer on all TFPs sold by TPT.

In connection with the formation of TPT, TPT assumed the obligations under our equipment purchase agreement with Marine Turbine Technologies, L.L.C., an entity owned and controlled by Mr. McIntyre, which assembled and supplied our first TFP under license from Mr. McIntyre. Under the equipment purchase agreement, we have an irrevocable, perpetual license and right to purchase up to 200 turbines and accessory equipment from MTT for use in our hydraulic fracturing and well services business as well as the right to resell, lease, and rent the turbine engines for such purposes to third parties.

Along with the equipment purchase agreement, we have entered into installation and maintenance agreements with TPT. Under these agreements, TPT provides all labor and professional supervisory and managerial personnel as are required for installation of turbine engines on trailers or into skids and maintains and repairs all turbine-powered equipment, accessory equipment, and all gearboxes and accessory gearboxes that we purchase. Under such agreements, we pay costs plus agreed upon markups to TPT.

TPT has arrangements with a supplier of turbine engines to acquire 50 re-manufactured turbine engines for $19.2 million with an option to acquire an additional 100 turbine engines at fixed prices as provided in the arrangements. As a consequence of our obligation under the installation agreement and amended equipment purchase agreement with TPT, we have become obligated to fund the costs to acquire the initial 50 and any subsequent purchases of turbine engines pursuant to TPT’s exercise of such option under TPT’s arrangements with its supplier.

Redemption and Earnout

Pursuant to redemption agreements entered into in May 2011 among the Company and certain of its members, the Company agreed to redeem all of its outstanding membership interests, other than those held by MMH. The redemption agreement of MMR was subsequently rescinded. Following a cash payment to Egle in the amount of approximately $0.7 million by the Company and the assumption by MMH of the remainder of the Company’s obligation to Egle in the amount of $3.0 million, the Company satisfied its initial purchase obligation pursuant to the Egle redemption agreement. Please read the section titled “Business—Corporate Reorganization—Equity Redemptions and Repurchases.”

In addition to such upfront payments, the redemption agreements provide that the Company make earnout payments to the members based on a percentage of the Company’s gross revenues attributable to its hydraulic fracturing services, in an aggregate amount not to exceed 3.36% of such revenues. Such earnout payments are to be made to such members until an aggregate total of $35.7 million is paid. The earnout payments accrue from the date of the closing of each respective redemption agreement and are payable, in arrears, no later than the 15^th of the month following each calendar quarter with respect to existing hydraulic fracturing spreads (commencing with the calendar quarter ended September 30, 2011). With respect to new hydraulic fracturing spreads, earnout payments will commence twelve months after such new hydraulic fracturing spreads are placed in service.

Dynamic Industries, Inc. Agreement

In April 2011, we entered into an agreement with Dynamic under which Dynamic promises to provide the material and labor for producing hydraulic fracturing units according to our specifications. Our Chairman and Chief Executive Officer, Michel B. Moreno, owns and controls Dynamic. Such agreement contains hourly labor rates and customary markups for materials and subcontracted services. The agreement can be terminated upon written notice by either party. During the three month period ended March 31, 2012 $4.4 million was paid to Dynamic for fixed asset purchases.

Aircraft Leases

In June 2011, we entered into two aircraft leases with entities controlled by our Chairman and Chief Executive Officer, Michel B. Moreno. Pursuant to these aircraft leases, the Company has access to two, non-commercial

aircraft that we can utilize from time to time to transport our personnel on a rental basis for appropriate business-only travel. For the quarter ended March, 31, 2012, $330,000 was paid to Aerodynamic, LLC for the aircraft lease. In addition, $0 was paid to Aerodynamic, LLC for flight charges and $356,632 was paid to Casafin II, LLC for flight charges.

Agreements with Entities Controlled by our Stockholders

We have entered into an agreement to purchase chemicals from Chemrock Technologies, LLC, a chemical company, in which MMR, one of our stockholders, has a 50% ownership interest. The contract calls for preferred pricing and will result in payments that could exceed $50.0 million dollars in 2012. We paid Chemrock $2,186,019 in the quarter ended March 31,2012. We will also purchase chemicals from unrelated vendors.

We have also entered into an agreement with Alliance Consulting Group. Alliance will build and operate a Wet and Dry processing plant that will perform the mining, processing and transportation of raw fracturing sand from these mines to support a portion of our own fracturing sand needs as well as demand from other consumers of fracturing and other types of sand. Our Chairman and Chief Executive Officer, Michel B. Moreno, has a controlling interest in Elle Investments, LLC which is a 50% owner of Alliance. We will pay Alliance $29 a ton for these services, approximately $29.0 million a year, and as of June 8, 2012 had prepaid Alliance $4 million which will offset future costs.

Please see the section titled “Business—Corporate Structure.” We may in the future use services provided by or acquire other materials or equipment from companies owned or partially owned by our stockholders. Any such arrangements will be pursuant to written agreements negotiated at arm’s length on the basis of competitive market pricing and other market terms and conditions.

Moreno, Fontova and Blackwell Employment Agreements

We have entered into employment agreements with Enrique “Rick” Fontova, our President, Michel B. Moreno, our Chief Executive Officer, and Earl J. Blackwell, our Chief Financial Officer. Mr. Moreno has beneficial ownership of more than 5% of the equity of the Company. Item 11 “Executive Compensation—Employment Agreements” describes such agreements and such description is incorporated herein by reference.

Eglé Transactions

We previously had an employment agreement with John M. Eglé, who was the Chief Executive Officer of the Company until May 1, 2011. We entered into a new employment agreement, effective May 1, 2011, with Mr. Eglé under which he will serve as the Special Assistant to Michel B. Moreno, our current Chief Executive Officer. The agreement provides for a two-year term of employment, with the second year conditioned upon Mr. Eglé booking international sales in excess of $1 million during the first year. The agreement provides that upon termination of employment voluntarily or by us for cause we shall pay to him accrued and unpaid base salary as of the date of termination. If Mr. Eglé’s employment terminates due to disability or death, we shall pay to Mr. Eglé or his estate accrued and unpaid base salary, plus one month or two months, respectively, additional base salary. If we terminate Mr. Eglé’s employment without cause we must continue to pay his base salary as it becomes due for the remaining term of the agreement. The agreement provides for a competitive base salary, a percentage of revenue directly generated by Mr. Eglé from international sales, an automobile allowance and all costs associated with participation in our health and disability benefit plans. Mr. Eglé is subject to customary non-competition, non-solicitation of customers and employees and confidentiality provisions.

Prior to May 1, 2011, Mr. Eglé beneficially owned more than 5% of the equity of the Company through his affiliate, Egle. On May 1, 2011, in addition to Mr. Eglé’s new employment agreement, we entered into a redemption agreement with Egle to redeem all of its equity in the Company. Under the redemption agreement, Egle was to be paid upfront cash payments of a total of approximately $3.8 million and an earnout payment of a

percentage of the gross revenues from hydraulic fracturing services of the Company until a total of approximately $3.4 million was paid. Prior to the private offering of the 13% notes Egle was paid a portion of the upfront cash payments and MMH assumed the remainder of that obligation on October 14, 2011. During the time the upfront cash payment remained outstanding our obligation to Mr. Eglé did not have an interest rate and we did not pay any interest. Please read also the section titled “Business—Corporate Reorganization—Equity Redemptions and Repurchases.”

Elle Investments, LLC

During the year ended December 31, 2011, we incurred $2.5 million of indebtedness from Elle Investments, LLC, an entity beneficially owned by Michel B. Moreno, our Chairman and Chief Executive Officer. These funds were utilized to procure equipment. We repaid this indebtedness in full prior to December 31, 2011.

Description of Common Stock

Our authorized capital stock consists of 2.0 million shares of common stock, $0.01 par value per share. There are currently 1.4 million shares of common stock outstanding, held of record by two stockholders.

The following description summarizes some of the terms of our common stock. Because it is only a summary, it does not contain all the information that may be important to you. For a complete description you should refer to our certificate of incorporation, as amended, and bylaws.

Voting, Dividend and Other Rights

Each share of common stock entitles the holder to one vote with respect to each matter presented to our stockholders on which the holders of common stock are entitled to vote. Our common stock votes as a single class on all matters, including all matters relating to the election and removal of directors on our Board of Directors. Holders of our common stock will not have cumulative voting rights. Except in respect of matters relating to the election and removal of directors on our Board of Directors and as otherwise provided in our certificate of incorporation, as amended, our bylaws, the rules and regulations of any stock exchange applicable to us, or any law or regulation applicable to us or our securities, all matters to be voted on by our stockholders must be approved by a majority in voting power of the shares present in person or by proxy at the meeting and entitled to vote on the matter. In the case of the election of directors at a meeting at which there is a quorum, directors will be elected by a plurality of the votes cast at such meeting.

The holders of our common stock are entitled to receive, from funds legally available for the payment thereof, dividends, if any, when and if declared by resolution of the Board of Directors, subject to certain restrictions in the indenture governing our 13% notes on the payment of dividends on our common stock. We have never declared or paid any cash dividends on our common stock. We do not intend to pay any cash dividends on our common stock for the foreseeable future. Any determination to pay dividends in the future will be at the discretion of our Board of Directors and will depend upon results of operations, capital requirements, financial condition, contractual restrictions, restrictions imposed by applicable law and other factors our Board of Directors deems relevant.

In the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs, holders of common stock would be entitled to share ratably in our assets that are legally available for distribution to stockholders after payment of our debts and other liabilities.

The holders of our common stock have no preemptive or conversion rights or other subscription rights. There are no redemption or sinking fund provisions applicable to our common stock.

Delaware Law and Certain Certificate of Incorporation and Bylaw Provisions

Number of Directors; Vacancies

Our bylaws provide that our Board of Directors must consist of one or more members. The Board of Directors, or its remaining members, even though less than a quorum, is empowered to fill vacancies on the Board of Directors occurring for any reason. A description of the composition of our Board of Directors is described in “Management.”

Actions Taken by the Board

In order for our Board of Directors to approve an action at a board meeting, the presence of directors entitled to cast a majority of the votes of the whole Board of Directors shall constitute a quorum. Except as otherwise provided by our certificate of incorporation, bylaws or applicable law, a majority of the votes entitled to be cast by directors present at the meeting at which there is a quorum shall be the act of the Board of Directors. Our Board of Directors can take an action without holding a meeting if it does so by unanimous written consent.

Amendments to the Certificate of Incorporation

The Delaware General Corporation Law allows us to amend our certificate of incorporation at any time to add or change a provision that is required or permitted to be included in the certificate of incorporation or to delete a provision that is not required to be included in the certificate of incorporation. The Board of Directors may amend our certificate of incorporation only with the approval of a majority in voting power of our stockholders.

Action by Written Consent of Stockholders

The Delaware General Corporation Law and our bylaws provide that any action required or permitted to be taken at a meeting of stockholders can be taken by written consent signed by the holders of our common stock holding equal to or greater than the number of shares of common stock that would have been required to approve such action at a meeting of stockholders at which all shares entitled vote on such action were present and voted.

Amendments to the Bylaws

Our bylaws and certificate of incorporation provide that our Board of Directors has the power to alter, amend or repeal the bylaws. Our stockholders also have the power to alter, amend or repeal any bylaws whether adopted by them or otherwise.

Delaware Business Combination Provisions

By a provision in our certificate of incorporation, we have opted not to be governed by the provisions of Section 203 of the General Corporation Law of Delaware, which regulates certain corporate takeovers.

Shares Eligible for Future Sales

Assuming exercise in full of all of the warrants and sale of all 247,058 shares of common stock being offered by the selling shareholders, we will have 1,647,058 shares of common stock outstanding. Of these shares, 247,058 will be freely transferable without restriction or further registration under the Securities Act by persons other than “affiliates,” as that term is defined in Rule 144 under the Securities Act. Generally, the balance of our outstanding shares of common stock are “restricted securities” within the meaning of Rule 144 under the Securities Act, subject to the limitations and restrictions that are described below. Shares of common stock purchased by our affiliates will be “restricted securities” under Rule 144A. Restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration under Rules 144 or 701 promulgated under the Securities Act.

Rule 144 Limitations

The availability of Rule 144 will vary depending on whether restricted securities are held by an affiliate or a non-affiliate. In general, under Rule 144, an affiliate who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell within any three-month period, a number of shares of common stock that does not exceed 1% of the number of shares of common stock then outstanding, which will equal approximately 16,470 shares after the filing of this registration statement, assuming exercise in full of all the warrants. Sales under Rule 144 are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about our Company. The volume limitations, manner of sale and notice provisions described above will not apply to sales by non-affiliates. For purposes of Rule 144, a non-affiliate is any person or entity who is not our affiliate at the time of sale and has not been our affiliate during the preceding three months. A non-affiliate who has beneficially owned restricted securities for six months may rely on Rule 144 provided that certain public information regarding us is available. A non-affiliate who has beneficially owned the restricted securities proposed to be sold for at least one year will not be subject to any restrictions under Rule 144.

Registration Rights Agreements

In connection with the sale of the 13% notes and accompanying warrants, we entered into a registration rights agreement with certain holders who, as a result of their ownership of common stock, might be characterized as “underwriters”. To our knowledge, these holders have the right to acquire upon exercise of their warrants a total of 247,058 shares of common stock.

Warrants

As of June 1, 2012, there were outstanding 250,000 warrants exercisable for a total of 247,058 shares of common stock at an exercise price of $0.01 per share.

Material U.S. Federal Income Tax Considerations

The following is a summary of the material U.S. federal income tax consequences to non-U.S. holders (as defined below) of the acquisition, ownership and disposition of our common stock. This discussion is not a complete analysis of all of the potential U.S. federal income tax consequences relating thereto, nor does it address any estate and gift tax consequences or any tax consequences arising under any state, local or non-U.S. tax laws, or any other U.S. federal tax laws. This discussion is based on the Internal Revenue Code of 1986, as amended, or the Code, Treasury Regulations promulgated thereunder, judicial decisions, and published rulings and administrative pronouncements of the Internal Revenue Service, or IRS, all as in effect as of the date of this offering. These authorities may change, possibly retroactively, resulting in U.S. federal income tax consequences different from those discussed below. No ruling has been or will be sought from the IRS with respect to the matters discussed below, and there can be no assurance the IRS will not take a contrary position regarding the tax consequences of the acquisition, ownership or disposition of our common stock, or that any such contrary position would not be sustained by a court.

This discussion is limited to non-U.S. holders who purchase our common stock pursuant to this prospectus and who hold such common stock as a “capital asset” within the meaning of Section 1221 of the Code (generally, property held for investment). This discussion does not address all of the U.S. federal income tax consequences that may be relevant to a particular holder in light of such holder’s particular circumstances. This discussion also does not consider any specific facts or circumstances that may be relevant to holders subject to special rules under the U.S. federal income tax laws, including, without limitation:

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financial institutions, banks and thrifts;

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insurance companies;

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tax-exempt organizations;

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partnerships or other pass-through entities;

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real estate investment trusts or regulated investment companies;

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traders in securities that elect to mark to market;

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broker-dealers or dealers in securities or currencies;

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U.S. expatriates;

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“controlled foreign corporations”, “passive foreign investment companies” or corporations that accumulate earnings to avoid U.S. federal income tax;

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persons that own, or are deemed to own, more than five percent (5%) of our outstanding common stock (except to the extent specifically set forth below);

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persons deemed to sell our common stock under the constructive sale provisions of the Code;

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persons who hold or receive our common stock pursuant to the exercise of any employee stock option or otherwise as compensation;

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persons subject to the alternative minimum tax; or

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persons that hold our common stock as a position in a hedging transaction, “straddle”, “conversion transaction” or other risk reduction transaction.

THIS DISCUSSION IS FOR GENERAL INFORMATION ONLY AND IS NOT TAX ADVICE. PROSPECTIVE INVESTORS SHOULD CONSULT THEIR TAX ADVISORS REGARDING THE PARTICULAR U.S. FEDERAL INCOME TAX CONSEQUENCES TO THEM OF ACQUIRING, OWNING AND DISPOSING OF OUR COMMON STOCK, AS WELL AS ANY TAX CONSEQUENCES ARISING UNDER ANY STATE, LOCAL OR NON-U.S. TAX LAWS AND ANY OTHER U.S. FEDERAL TAX LAWS.

Definition of Non-U.S. Holder

For purposes of this discussion, a non-U.S. holder is any beneficial owner of our common stock that is not a “U.S. person” or a partnership for U.S. federal income tax purposes. A U.S. person is any of the following:

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an individual who is a citizen or resident of the United States;

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a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized under the laws of the United States, any state thereof or the District of Columbia;

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an estate the income of which is subject to U.S. federal income tax regardless of its source; or

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a trust (1) whose administration is subject to the primary supervision of a U.S. court and which has one or more U.S. persons who have the authority to control all substantial decisions of the trust, or (2) that has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person.

If a partnership holds our common stock, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding our common stock should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the common stock.

Distributions on Our Common Stock

We do not intend to pay dividends on our common stock for the foreseeable future. However, if we make cash or other property distributions on our common stock, such distributions generally 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 U.S. federal income tax principles. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and will first be applied against and reduce a non-U.S. holder’s tax basis in the common stock, but not below zero. Distributions in excess of our current and accumulated earnings and profits and in excess of a non-U.S. holder’s tax basis in its shares will be taxable as capital gain realized on the sale or other disposition of the common stock and will be treated as described under “Dispositions of Our Common Stock” below.

Dividends paid to a non-U.S. holder of our common stock generally will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends, or such lower rate specified by an applicable income tax treaty. To receive the benefit of a reduced treaty rate, a non-U.S. holder generally must furnish to us or our paying agent a valid IRS Form W-8BEN (or applicable successor form) certifying such holder’s qualification for the reduced rate. This certification must be provided to us or our paying agent prior to the payment of dividends and must be updated periodically. Non-U.S. holders that do not timely provide us or our paying agent with the required certification, but that qualify for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under an applicable income tax treaty.

Dividends paid on our common stock that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, are attributable to a permanent establishment maintained by the non-U.S. holder in the United States) will be exempt from U.S. federal withholding tax. To claim the exemption, the non-U.S. holder must generally furnish to us or our paying agent a properly executed IRS Form W-8ECI (or applicable successor form).

Any dividends paid on our common stock that are effectively connected with a non-U.S. holder’s U.S. trade or business (and if required by an applicable income tax treaty, attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be subject to U.S. federal income tax on a net income basis at the regular graduated U.S. federal income tax rates in much the same manner as if such holder were a resident of the United States. A non-U.S. holder that is a corporation also may be subject to an

additional branch profits tax equal to 30% (or such lower rate specified by an applicable income tax treaty) of its effectively connected earnings and profits for the taxable year, as adjusted for certain items. Non-U.S. holders should consult any applicable income tax treaties that may provide for different rules.

Dispositions of Our Common Stock

Subject to the discussion below regarding backup withholding, a non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock, unless:

•

the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States);

•

the non-U.S. holder is a nonresident alien individual present in the U.S. for 183 days or more during the taxable year of the disposition, and certain other requirements are met; or

•

our common stock constitutes a “U.S. real property interest” by reason of our status as a U.S. real property holding corporation, or USRPHC, for U.S. federal income tax purposes.

Gain described in the first bullet point above will be subject to U.S. federal income tax on a net income basis at the regular graduated U.S. federal income tax rates in much the same manner as if such holder were a resident of the U.S. A non-U.S. holder that is a corporation also may be subject to an additional branch profits tax equal to 30% (or such lower rate specified by an applicable income tax treaty) of its effectively connected earnings and profits for the taxable year, as adjusted for certain items. Non-U.S. holders should consult any applicable income tax treaties that may provide for different rules.

Gain described in the second bullet point above will be subject to U.S. federal income tax at a flat 30% rate (or such lower rate specified by an applicable income tax treaty), but may be offset by U.S. source capital losses (even though the individual is not considered a resident of the United States), provided that the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses.

With respect to the third bullet point above, we believe we are not currently and do not anticipate becoming a USRPHC for United States federal income tax purposes. However, because the determination of whether we are a USRPHC depends on the fair market value of our United States real property interests relative to the fair market value of our other trade or business assets and our non-United States real property interests, there can be no assurance that we are not a USRPHC or will not become one in the future. Even if we are a USRPHC, gain arising from the sale or other taxable disposition by a non-U.S. holder of our common stock will not be subject to tax if such class of stock is “regularly traded,” as defined by applicable Treasury Regulations, on an established securities market, and such non-U.S. holder owned, actually or constructively, 5% or less of such class of our stock throughout the shorter of the five-year period ending on the date of the sale or exchange or the non-U.S. holder’s holding period for such stock. We do not believe our common stock will be “regularly traded” on an established securities market within the meaning of applicable Treasury Regulations, and we cannot guarantee that the common stock will become regularly traded on an established securities market in the future. If gain on the sale or other taxable disposition of our stock were subject to taxation under the third bullet point above, the non-United States holder would be subject to regular United States federal income tax with respect to such gain in generally the same manner as a U.S. person.

Information Reporting and Backup Withholding

We must report annually to the IRS and to each non-U.S. holder the amount of distributions on our common stock paid to such holder and the amount, if any, of tax withheld with respect to those distributions. These information reporting requirements will apply in certain circumstances even if no withholding is required, such as where the distributions are effectively connected with the holder’s conduct of a U.S. trade or business or

withholding is reduced or eliminated by an applicable income tax treaty. This information also may be made available under a specific treaty or agreement with the tax authorities in the country in which the non-U.S. holder resides or is established. Backup withholding, however, generally will not apply to distributions to a non-U.S. holder of our common stock provided the non-U.S. holder furnishes to us or our paying agent the required certification as to its non-U.S. status, such as by providing a valid IRS Form W-8BEN or IRS Form W-8ECI, or certain other requirements are met. Notwithstanding the foregoing, backup withholding may apply if either we or our paying agent has actual knowledge, or reason to know, that the holder is a U.S. person that is not an exempt recipient.

Unless a non-U.S. holder complies with certification procedures to establish that it is not a U.S. person, information returns may be filed with the IRS in connection with, and the non-U.S. holder may be subject to backup withholding on the proceeds from, a sale or other disposition of our common stock. The certification procedures described in the above paragraph will satisfy these certification requirements as well.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a non-U.S. holder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Foreign Accounts

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, and gross proceeds from the sale or other disposition of, our common stock paid to a foreign financial institution or to a non-financial foreign entity, unless (1) the foreign financial institution undertakes certain diligence and reporting and enters into an agreement with the IRS requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S. owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to non-compliant foreign financial institutions and certain other account holders, (2) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner, or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules.

Although these rules currently apply to applicable payments made after December 31, 2012, the IRS has issued Proposed Treasury Regulations providing that the withholding provisions described above will generally apply to payments of dividends made on or after January 1, 2014 and to payments of gross proceeds from a sale or other disposition of common stock on or after January 1, 2015.

The Proposed Treasury Regulations described above will not be effective until they are issued in their final form, and as of the date of this prospectus, it is not possible to determine whether the proposed regulations will be finalized in their current form or at all. Prospective investors should consult their tax advisors regarding these withholding provisions.

Legal Matters

The validity of the shares of common stock offered by this prospectus will be passed upon for us by Latham & Watkins LLP, Houston, Texas.

Experts

The consolidated balance sheet of Green Field Energy Services, Inc. (the Company or Successor), formerly Green Field Energy Services, LLC, as of December 31, 2011, and the related consolidated statements of operations, equity, and cash flows for the period from May 1, 2011 to December 31, 2011, and the consolidated balance sheet of Hub City Industries, LLC (Predecessor) as of December 31, 2010, and the related consolidated statements of operations, equity, cash flows for the period from January 1, 2011 to April 30, 2011, and for the year ended December 31, 2010 appearing in this Prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given the authority of such firm as experts in accounting and auditing.

Information included in this prospectus regarding our estimated quantities of sand reserves was obtained from a report prepared by Terracon Consultants, Inc., independent geophysical engineers with respect to Green Field Energy Services, Inc.

Where You Can Find More Information

We have filed with the SEC a registration statement on Form S-1 with respect to the common stock being offered for resale by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common stock offered for resale by this prospectus, please review the full registration statement, including its exhibits.] The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of this material can also be obtained from the public reference section of the SEC at prescribed rates, or accessed at the SEC’s website at www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room.

The SEC’s proxy rules and regulations do not, nor do the rules of any stock exchange, require us to send an annual report to security holders. Upon the effectiveness of this registration statement, we will become subject to the Exchange Act’s periodic reporting requirements, including the requirement to file current, annual and quarterly reports with the SEC. The annual reports we file will contain financial information that has been audited and reported on, with an opinion by an independent certified public accounting firm.

Index to Consolidated Financial Statements


	PAGE
Audited Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2011 and 2010		F-3
Consolidated Statements of Operations for the periods May 1, 2011 to December 31, 2011 and January 1, 2011 to April 30, 2011 and for the year ended December 31, 2010		F-5
Consolidated Statements of Equity for the periods May 1, 2011 to December 31, 2011 and January 1, 2011 to April 30, 2011 and for the year ended December 31, 2010		F-6
Consolidated Statements of Cash Flows for the periods May 1, 2011 to December 31, 2011 and January 1, 2011 to April 30, 2011 and for the year ended December 31, 2010		F-7
Notes to Consolidated Financial Statements		F-8

Unaudited Consolidated Financial Statements

Consolidated Balance Sheets as of December 31, 2011 and March 31, 2012 (Unaudited)		F-29
Unaudited Consolidated Statements of Operations for the Three Months Ended March 31, 2011 and 2012		F-30
Unaudited Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2012		F-31
Notes to Unaudited Consolidated Financial Statements		F-32

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders of

Green Field Energy Services, Inc.

We have audited the accompanying consolidated balance sheet of Green Field Energy Services, Inc. (the Company or Successor), formerly Green Field Energy Services, LLC, as of December 31, 2011, and the related consolidated statements of operations, equity, and cash flows for the period from May 1, 2011 to December 31, 2011, and the consolidated balance sheet of Hub City Industries, LLC (Predecessor) as of December 31, 2010 and the related consolidated statements of operations, equity, and cash flows for the period from January 1, 2011 to April 30, 2011 and for the year 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. We were not engaged to perform an audit of the Company’s or the Predecessor’s internal control over financial reporting. Our audits 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 or the Predecessor’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, and 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 consolidated financial position of Green Field Energy Services, Inc. at December 31, 2011, and the consolidated results of its operations and its cash flows for the period from May 1, 2011 to December 31, 2011, and the consolidated financial position of Hub City Industries, LLC, at December 31, 2010, and the consolidated results of its operations and its cash flows for the period from January 1, 2011 to April 30, 2011 and for the year ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

LOGO

New Orleans, Louisiana

April 16, 2012

F-2

Green Field Energy Services, Inc.

Consolidated Balance Sheets


	PREDECESSOR			SUCCESSOR
	December 31, 2010			December 31, 2011
ASSETS

CURRENT ASSETS
Cash	$	838,713		$	87,118,385
Accounts receivable—net of allowance		5,867,948			3,965,654
Other receivables		1,236,663			18,483
Due from related parties		9,005			20,329
Inventory		378,785			347,489
Prepaid expenses		1,154,776			1,769,133

Total current assets		9,485,890			93,239,473

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		51,144,196			55,400,686
Construction in progress		2,962,131			115,415,402

		54,106,327			170,816,088
Less accumulated depreciation		(14,575,484	)		(5,208,019	)

		39,530,843			165,608,069

OTHER ASSETS
Deposits		358,858			4,910,546
Loan costs—net of accumulated amortization		7,019			8,136,473
Intangible assets		—			13,274,728
Goodwill		—			9,422,335
Other		—			10,589

		365,877			35,754,671

TOTAL ASSETS	$	49,382,610		$	294,602,213

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

F-3


	PREDECESSOR		SUCCESSOR
	December 31, 2010		December 31, 2011
LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	2,452,257	$	1,026,819
Accrued expenses		1,545,490		18,884,139
Due to members		189,366		—
Notes payable		380,349		429,604
Current portion of long-term debt		28,706,193		156,969
Current earn-out payable		—		2,520,000

Total current liabilities		33,273,655		23,017,531

LONG-TERM LIABILITIES
Long-term debt, net of current portion		—		336,047
Earn-out payable, net of current portion		—		21,329,637
Senior Notes		—		191,958,214
Deferred income taxes		26,032		—

		26,032		213,623,898

COMMITMENTS AND CONTINGENCIES

EQUITY
Common stock—$.01 par value, authorized 2,000,000 shares, issued and outstanding, 1,400,000 shares		—		14,000
Additional paid in capital		—		81,568,335
Accumulated deficit		—		(23,621,551	)
Members’ equity		16,082,923		—

Total equity		16,082,923		57,960,784

TOTAL LIABILITIES AND EQUITY	$	49,382,610	$	294,602,213

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

F-4

Green Field Energy Services, Inc.

Consolidated Statements of Operations


	PREDECESSOR			PREDECESSOR			SUCCESSOR
	YEAR ENDED DECEMBER 31, 2010			PERIOD FROM JANUARY 1, TO APRIL 30, 2011			PERIOD FROM MAY 1, TO DECEMBER 31, 2011
Revenue	$	28,362,237		$	14,445,519		$	18,625,394
Operating Costs
Cost of revenue		16,615,280			9,814,813			15,601,359
Selling and administrative expenses		4,031,260			2,001,562			11,654,140
Depreciation and amortization		4,602,326			1,723,932			9,395,607

Total operating costs		25,248,866			13,540,307			36,651,106

Income (loss) from operations		3,113,371			905,212			(18,025,712	)
Other income (expense):
Interest expense		(1,034,375	)		(364,126	)		(4,067,809	)
Other income (expense)		(468,298	)		44,181			(1,476,503	)

Net other expense		(1,502,673	)		(319,945	)		(5,544,312	)

Income (loss) before provision for income tax		1,610,698			585,267			(23,570,024	)
Income tax expense		77,853			63,231			51,527

Net income (loss)	$	1,532,845		$	522,036		$	(23,621,551	)

Unaudited pro forma financial information:
Income (loss) before income taxes		1,610,698			585,267			(23,570,024	)
Income tax expense (benefit)		77.853			63,231			51,527

Net income (loss)		1,532,845			522,036			(23,621,551	)

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

F-5

Green Field Energy Services, Inc.

Consolidated Statements of Equity

For the year ended December 31, 2010 and the period from January 1, 2011 to April 30, 2011


	CLASS A & B			CLASS C			TOTAL
PREDECESSOR
Balance, December 31, 2009	$	11,326,401		$	(187,508	)	$	11,138,893
Net income		1,532,845			—			1,532,845
Contributions		3,500,000			—			3,500,000
Distributions		(88,815	)		—			(88,815	)

Balance, December 31, 2010	$	16,270,431		$	(187,508	)	$	16,082,923

Net income		522,036			—			522,036
Contributions		—			—			—
Distributions		—			—			—

Balance, April 30, 2011	$	16,792,467		$	(187,508	)	$	16,604,959

For the period from May 1, 2011 to December 31, 2011


SUCCESSOR	MEMBERS’ EQUITY			COMMON STOCK		ADDITIONAL PAID-IN CAPITAL		ACCUMULATED DEFICIT			TOTAL
Initial contribution	$	686,750		$	—	$	—	$	—		$	686,750
Contributions		1,150,000			—		—		—			1,150,000
Conversion from LLC to Corporation		(1,836,750	)		12,460		1,824,290		—			—
Net loss		—			—		—		(23,621,551	)		(23,621,551	)
Contributions		—			—		3,000,000		—			3,000,000
Warrant issuance		—			—		53,873,064		—			53,873,064
Share issuance		—			1,540		22,870,981		—			22,872,521

Balance, December 31, 2011	$	—		$	14,000	$	81,568,335	$	(23,621,551	)	$	57,960,784

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

F-6

Green Field Energy Services, Inc.

Consolidated Statements of Cash Flows


	PREDECESSOR			PREDECESSOR			SUCCESSOR
	YEAR ENDED DECEMBER 31, 2010			PERIOD FROM JANUARY 1, TO APRIL 30, 2011			PERIOD FROM MAY 1, TO DECEMBER 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	1,532,845		$	522,036		$	(23,621,551	)
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities:
Depreciation and amortization		4,602,326			1,723,932			9,395,607
Increase in earnout payable		—			—			183,999
Loss (Gain) on sale of assets		105,132			(40,179	)		603
Deferred income taxes		(37,294	)		—			(26,032	)
(Increase) decrease in:
Accounts receivable		(3,023,382	)		(148,526	)		2,050,820
Other receivables		(1,116,313	)		(472,230	)		1,690,410
Inventory		(112,068	)		237,118			(205,822	)
Prepaid expenses		(407,529	)		703,514			(1,317,871	)
Other assets		(294,270	)		(133,964	)		(4,417,724	)
Increase (decrease) in:
Accounts payable		1,165,010			(898,530	)		(526,908	)
Accrued expenses		670,601			560,780			16,754,920

Total adjustments		1,552,213			1,531,915			23,582,002

Net cash provided (used) by operating activities		3,085,058			2,053,951			(39,549	)

CASH FLOWS FROM INVESTING ACTIVITIES
Cash payments for the purchase of property		(2,572,188	)		(338,716	)		(119,647,129	)
Proceeds from the sale of property		151,020			83,118			1,314
Acquisition of Green Field		—			—			(686,750	)

Net cash used by investing activities		(2,421,168	)		(255,598	)		(120,332,565	)

CASH FLOWS FROM FINANCING ACTIVITIES
Due to/from owners and affiliates		234,398			113,411			(314,101	)
Cash—restricted		1,123,876			—			—
Proceeds from issuance of Senior Notes		—			—			247,500,000
Proceeds from issuance of long-term debt		—			—			57,747,628
Debt issuance costs		—			—			(14,012,797	)
Principal payments on long-term debt		(4,815,793	)		(1,119,803	)		(86,210,905	)
Capital contributions		3,500,000			—			1,150,000
Distributions Paid		(88,815	)					—

Net cash (used) provided by financing activities		(46,334	)		(1,006,392	)		205,859,825

Net increase in cash		617,556			791,961			85,487,711
CASH AND CASH EQUIVALENTS, beginning of year		221,157			838,713			1,630,674

CASH AND CASH EQUIVALENTS, end of year	$	838,713		$	1,630,674		$	87,118,385

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid	$	1,348,230		$	284,568		$	3,575,451

Income taxes paid	$	63,104		$	—		$	—

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

F-7

Green Field Energy Services, Inc.

Notes to Consolidated Financial Statements

NOTE 1 SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES

Description of Business

Formed in 1969, the Company is an independent oilfield services company that provides a wide range of services to oil and natural gas drilling and production companies in Louisiana and Texas to help develop and enhance the production of hydrocarbons. The Company’s services include hydraulic fracturing, cementing, coiled tubing, pressure pumping, acidizing and other pumping services.

The Company began providing hydraulic fracturing services in December 2010. To support its hydraulic fracturing operations, it has also entered into two long-term leases during 2011 for sand mines in Louisiana and Mississippi. These mines are expected to supply a portion of its fracturing sand needs and provide the Company the opportunity to sell fracturing sand to third parties.

The Company currently provides services to a diverse group of major and large independent oil and natural gas companies.

Basis of Presentation

During May 2011, through a series of transactions, the Company redeemed all of the existing members’ ownership interests for cash payments of $2.2 million, an obligation to pay $30.7 million and contingent consideration of up to $30.0 million based on revenues that are earned from the Company’s frac turbine units. A new member was admitted for a cash contribution of $0.7 million. This series of transactions resulted in a change of control of the Company which required a new basis of accounting be established as of the date of the change in control. As a result, all assets and liabilities of the Company were required to be recognized at their fair value. See Note 13 for more information. Due to this, the consolidated financial statements and certain disclosures are presented in distinct periods to indicate the application of the two bases of accounting. The term “Predecessor” refers to the Company prior to the change in control and the term “Successor” refers to the Company following the change in control.

Principles of Consolidation

The accompanying financial statements include the consolidated accounts of Green Field Energy Services, Inc., a Delaware corporation (formerly Hub City Industries, LLC, Green Field Energy Services, LLC, and Green Field Energy Services, Inc., a Louisiana corporation), Hub City Tools, Inc., and Proppant One, Inc.. During 2011, the Company formed Proppant One, a wholly owned subsidiary, to market the Company’s sand operations. These companies are collectively hereafter referred to as the Company. The Company consolidates majority owned subsidiaries and any variable interest entities (VIEs) of which it is the primary beneficiary. When it does not have a controlling interest in an entity, but exerts a significant influence over the entity, it applies the equity method of accounting. The cost method is used when it does not have the ability to exert significant influence. All significant inter-company balances and transactions have been eliminated in the consolidated statements.

Revenue Recognition

Revenues are recognized in the Company’s well and hydraulic fracturing services operations as services are completed and accepted by their customer. With respect to the Company’s hydraulic fracturing services, the Company recognizes revenue and invoices its customers upon the completion of each fracturing stage. The Company typically completes one or more fracturing stages per day during the course of a job. A stage is considered complete when the Company has met the specifications set forth in their contract with the customer for the number of hours their equipment is in use or the volume of sand used, or when the pressure exceeds the

F-8

maximum specified in the contract for their 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 its services.

Revenues from the Company’s top 5 customers accounted for approximately 38 % and 52% of total revenues for the years ended December 31, 2010 and 2011, respectively.

Change of Legal Organization

On September 1, 2011, the Company changed its name from Hub City Industries, LLC to Green Field Energy Services, LLC. In October 2011, Green Field Energy Services, LLC became a “C” Corporation of Louisiana, then pursuant to its senior notes offering, the Company converted to a Delaware Corporation whereby all shares of stock issued and outstanding prior to the Delaware conversion became 1,000 shares of issued and outstanding shares of common stock for the newly converted Delaware Corporation. In November 2011, in an amendment to the Certificate of Incorporation, the Company authorized a 1,400 shares to 1 stock split for each share of common stock outstanding.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents.

Inventory

Inventory, consisting of various solvents and parts, is valued at the lower of cost or market value determined on the FIFO method.

Loan Costs

Loan costs are carried on the books net of accumulated amortization. Amortization is calculated on an effective interest basis over the expected life of the loan or notes. Amortization expense was $4,679 and $4,208,737 for the years ended December 31, 2010 and 2011, respectively.

Income taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due plus deferred taxes. Income tax expense is based on income reported in the accompanying consolidated statements of operations adjusted for differences that will never enter into the computation of taxes payable under applicable tax laws. Deferred taxes are recognized for differences between the basis of assets and liabilities for financial statements and income tax purposes. Prior to its conversion to a C Corporation effective October 1, 2011, the income of Hub City Industries, LLC and Green Field Energy Services, LLC, which were treated as a partnership for federal income tax purposes, was passed through to its members and accordingly no federal and, where applicable, state taxes were paid by this entity. Consequently, no provision for income taxes was recorded for this entity in the accompanying financial statements prior to October 1, 2011. On October 1, 2011, in connection with its conversion to a C Corporation, the Company recorded approximately $5 million in net deferred tax asset related to existing cumulative temporary differences as of that date.

Deferred tax assets and liabilities are identified separately as current or noncurrent based on the classification of the related asset or liability. A deferred tax asset or liability not associated with an asset or liability for financial reporting purposes is classified as current or noncurrent according to the expected reversal date of the temporary difference.

F-9

Goodwill

Goodwill represents the excess of the consideration paid over the fair value of the net assets acquired as a result of the change in control that occurred in May 2011. See Note 13. Goodwill is evaluated for impairment at least annually in accordance with the provisions of ASC 350, Intangibles—Goodwill and Other. As of October 1, 2011, the date of the annual impairment assessment, no impairment of goodwill was noted.

Intangible assets

The Company amortizes intangible assets with finite lives on a straight-line basis over their estimated useful lives. Customer lists are amortized over fifteen years. Covenants not to compete are amortized over five years. Intangible assets are reviewed annually for impairment or when events or circumstances indicate their carrying amounts may not be recoverable. No impairments were recorded for the year ended December 31, 2011.

Depreciation

Fixed assets were adjusted to fair value as of May 2011 as discussed in Note 13, which established a new cost basis for fixed assets as of that date. Depreciation, for financial statement purposes, is provided by the straight-line method over the estimated useful lives of the assets as follows:


Leasehold improvements			7-39
Vehicles			5-7
Furniture			5-7
Equipment			3-10

Gains or losses on sales of these assets are credited or charged to other income or other deductions. When events or changes in circumstances indicate that assets may be impaired, an evaluation is performed by comparing the undiscounted cash flows to be generated by the assets to its carrying value. The impairment loss is measured by the estimated fair value of the asset compared to the asset’s carrying amount with the difference recorded as an impairment.

Advertising Costs

Advertising costs are expensed as incurred.

Fair Value Measurements

ASC 820, Fair Value Measurements and Disclosures (ASC 820), establishes a hierarchy that prioritizes inputs to valuation techniques used to measure fair value and requires companies to disclose the fair value of their financial instruments according to a fair value hierarchy (i.e., Level 1, 2, and 3 inputs, as defined). The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. Additionally, companies are required to provide enhanced disclosure regarding instruments in the Level 3 category (which use inputs to the valuation techniques that are unobservable and require significant management judgment), including a reconciliation of the beginning and ending balances separately for each major category of assets and liabilities.

Financial instruments measured and reported at fair value are classified and disclosed in one of the following categories:

Level 1 Inputs—Quoted prices (unadjusted) in active markets for identical assets or liabilities at the reporting date.

Level 2 Inputs—Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities that are not active; and inputs other than quoted market prices that are observable, such as models or other valuation methodologies.

F-10

Level 3 Inputs—Unobservable inputs for the valuation of the asset or liability. Level 3 include assets or liabilities for which there is little, if any, market activity. These inputs require significant management judgment or estimation.

Uses of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Subsequent Events

Management has evaluated subsequent events through April 16, 2012, the date the financial statements were available to be issued. Refer to Note 9 for a discussion of subsequent transactions entered into in 2012.

New Accounting Pronouncements

In May 2011, the FASB issued amended guidance on fair value measurements to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. The amended guidance specifies that the concepts of highest and best use and valuation premise in a fair value measurement are relevant only when measuring the fair value of nonfinancial assets and are not relevant when measuring the fair value of financial assets or of liabilities. With respect to financial instruments that are managed as part of a portfolio, an exception to fair value requirements is provided. The guidance also requires enhanced disclosures about fair value measurements, including, among other things, (a) for fair value measurements categorized within Level III of the fair value hierarchy, (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) the valuation process used by the reporting entity, and (3) a narrative description of the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any, and (b) the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed (for example, a financial instrument that is measured at amortized costs in the statement of financial position by for which fair value is disclosed). The guidance also amends disclosure requirements for significant transfers between Level I and Level II and now requires disclosure of all transfer between Levels I and II in the fair value hierarchy. The amended guidance is effective for interim and annual periods beginning December 15, 2011. As the impact of the guidance is primarily limited to enhanced disclosures, adoption is not expected to have a material impact on the Company’s financial statements.

NOTE 2 ACCOUNTS

RECEIVABLE

The Company provides for doubtful accounts using the allowance method. For the years ended December 31, 2010 and 2011, the allowance deemed necessary was $197,333 and $37,272, respectively. For the years ended December 31, 2010 and 2011, the Company incurred bad debts of $200,020 and $108,722, respectively.

Below is a schedule of accounts receivable as of December 31, 2010 and 2011:


	2010			2011
Accounts receivable		6,065,281			4,002,926
Allowance for doubtful accounts		(197,333	)		(37,272	)

Accounts receivable—net of allowance	$	5,867,948		$	3,965,654

F-11

NOTE 3 PROPERTY,

PLANT AND EQUIPMENT

Below is a schedule of property, plant and equipment as of December 31, 2010 and 2011:


	2010			2011
Equipment	$	44,316,733		$	42,391,220
Furniture and fixtures		146,621			230,140
Leasehold improvements		249,945			453,296
Building		1,636,642			1,505,219
Rental equipment		68,220			68,220
Land		333,679			1,078,400
Computer equipment		383,409			349,960
Vehicles		4,008,947			9,324,231
Construction in progress—equipment		2,962,131			115,415,402

		54,106,327			170,816,088
Less: Accumulated depreciation and amortization		(14,575,484	)		(5,208,019	)

Net property, plant and equipment	$	39,530,843		$	165,608,069

In connection with the change in control described in Note 13, the Company recognized its property, plant and equipment at fair value as of May 2011.

The Company had $2,962,131 and $115,415,402 in construction in progress at December 31, 2010 and 2011, respectively, which includes self- constructed equipment to be used for future operations.

In addition, the Company has approximately $92,983,994 of commitments for additional expenditures to be incurred in 2012 and future years in order to complete construction on the remaining $115,415,402 of the above self-constructed units.

Depreciation expense charged to operations was $4,602,326 and $6,910,802 for the years ended December 31, 2010 and 2011, respectively. For the years ended December 31, 2010 and 2011, the Company capitalized interest totaling $171,882 and $4,596,941, respectively.

NOTE 4 INTANGIBLE

ASSETS

Intangible assets consist of the following as of December 31, 2011:


Customer lists	$	12,909,000
Covenant not to compete		1,084,000

		13,993,000
Less: Accumulated amortization		718,272

Net	$	13,274,728

Amortization expense related to intangible assets for the year ended December 31, 2011 was $718,272. Annual future aggregate estimated amortization expense of intangible assets for the next 5 years is as follows:


2012	$	1,077,408
2013		1,077,408
2014		1,077,408
2015		1,077,408
2016		932,855
Thereafter		8,032,241

	$	13,274,728

F-12

There were no intangible assets recorded as of December 31, 2010. Refer to Note 13.

NOTE 5 NOTES

PAYABLE


	2010		2011
Note payable to TMC/Midsouth Bank, NA, dated September 28, 2011, original amount of $177,319 bearing interest at 4.262% per annum, payable in 10 monthly installments of $18,080, collateralized by insurance policies.	$	—	$	124,778

Note payable to TMC/Midsouth Bank, NA, dated July 15, 2011, original amount of $663,569 bearing interest at 4.25% per annum, payable in 10 monthly installments of $61,615, collateralized by insurance policies.		—		304,826

Note payable to BankDirect Capital Finance, dated July 1, 2010, original amount of $732,366, bearing interest at 4.79% per annum, payable in 13 monthly installments of $69,805, collateralized by insurance policies.		380,349		—

Total notes payable	$	380,349	$	429,604

NOTE 6 LONG-TERM

DEBT


	2010		2011
Senior notes payable in the face amount of $250,000,000, consisting of 250,000 units of $1,000 principal amounts of 13% senior secured notes due 2016.	$	—	$	191,958,214

Term notes payable to Ford Motor Credit, various dates, payable in 36 monthly installments of $830 to $1,334, bearing interest at 4.24% to 6.54% per annum, secured by vehicles.		—		493,016

Revolving line of credit to JP Morgan Chase Bank dated December 3, 2007, in the amount of $3,000,000, bearing interest at 3.5% above the index per annum, monthly payments of interest commencing on January 1, 2008, principal payment due on May 31, 2010, secured by equipment, inventory, deposit accounts and the continuing guaranty of member		3,000,000		—

CAPEX note to JP Morgan Chase Bank dated June 30, 2009 in the amount of $3,000,000 bearing interest at 5.5% per annum, principal payments of 30 monthly installments of $35,714 plus interest, commencing on January 30, 2010, and one final payment on July 30, 2012, secured by equipment, inventory, deposit accounts, and the continuing guaranty of members		2,571,403		—

Term note payable to JP Morgan Chase Bank dated June 30, 2009, in the amount of $698,947, bearing interest at 3.5% above the index (currently 3.76%) per annum, principal payments of 96 monthly installments of $6,989 plus interest, commencing on July 26, 2009, with a final payment on August 26, 2017, secured by equipment, inventory, deposit accounts, and the continuing guaranty of members		573,137		—

Term note payable to JP Morgan Chase Bank dated June 30, 2009, in the amount of $16,000,000, bearing interest at 3.5% above the index (currently 3.76%) per annum, monthly payments of $1,000,000, plus interest, for 6 months, commencing on July 31, 2009, then 29 monthly payments of interest, commencing on January 30, 2010, with principal due in full on June 30, 2012, secured by equipment, inventory, secured by equipment, inventory, deposit accounts, and the continuing guaranty of members		10,000,000		—

F-13


	2010		2011

Term note payable to JP Morgan Chase Bank dated June 30, 2009, in the amount of $16,292,000, bearing interest at 3.5% above the index (currently 3.76%) per annum, payable in 35 monthly installments of $193,952 plus interest, commencing on July 31, 2009, and 1 final payment of principal balance on July 31, 2016, secured by equipment, inventory, deposits, and the continuing guaranty of members		12,561,653		—

Total		28,706,193		192,451,230
Less: current maturities of long-term debt		28,706,193		156,969

Net long-term debt and senior notes payable	$	—	$	192,294,261

Future debt maturities are as follows:
2012		—	$	156,969
2013		—	$	168,782
2014		—	$	167,265
2015		—	$	—
2016 and thereafter		—	$	250,000,000

The Company was in violation of a financial covenant at December 31, 2010 of the JP Morgan agreements. The Bank waived this covenant violation but the Company was out of compliance in subsequent periods. All outstanding debt to JP Morgan, $28,706,193, was repaid in May 2011.

On November 15, 2011, the Company issued 250,000 units, each consisting of $1,000 principal amount of 13% senior secured notes due 2016 (the Notes) and one warrant to purchase .988235 shares of the Company’s common stock (the Warrants). The units were issued at a price of $990 per unit and resulted in net proceeds of $241.6 million after deducting fees and expenses related to the offering.

The units were issued to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The Company also entered into a registration rights agreement with respect to the Notes whereby the Company has agreed to make an offer to exchange the Notes for registered, publicly tradable securities that have substantially identical terms as the Notes. The exchange offer would be completed through the filing of a registration statement with the Securities and Exchange Commission (SEC) no later than 210 days after the offering with such registration statement being declared effective on or prior to 300 days after the offering and the exchange offer consummated within 30 business days after such registration statement is declared effective. Additionally, the Company entered into a registration rights agreement with respect to the warrant shares whereby the Company has agreed to file a shelf registration statement with the SEC covering the relate of the warrant shares no later than 210 days after the offering and to use commercially reasonable efforts to cause such registration statement to be declared effective no later than 300 days after the offering.

The Notes mature on November 15, 2016 and bear interest at a fixed annual rate of 13%, to be payable semi-annually on May 15 and November 15 of each year, with the first interest payment made on May 15, 2012. The Notes are fully and unconditionally and irrevocably guaranteed, jointly and severally, on a senior secured basis by each of the Company’s existing and future domestic restricted subsidiaries.

The Notes are secured by a security interest on substantially all of the Company’s tangible and intangible assets subject to certain exceptions. However, if the Company enters into a senior credit facility in an aggregate principal amount not exceeding the greater of $30.0 million and a specified percentage of the Company’s tangible assets, such security interest and pledge will be contractually subordinated to the liens thereon that secure such senior credit facility, pursuant to an intercreditor agreement. The Notes rank senior in right of payment to all of the Company’s existing and future subordinated indebtedness but will be effectively subordinated to the senior credit facility discussed above to the extent of the value of the collateral secured thereby.

F-14

The Company may redeem the Notes in whole or in part on or after November 15, 2014 at a redemption price of 109.75% of principal amount in 2014 and 100% of principal amount in 2015 and thereafter. Prior to November 15, 2014, the Company may, at its option, redeem up to 35% of the aggregate principal amount of the Notes at a redemption price of 113% of principal amount with the proceeds of certain equity offerings. Additionally, the Company may, at its option, redeem the Notes at any time prior to November 15, 2014 at a price equal to 100% of the principal amount of the Notes redeemed by paying a make whole premium.

If the Company experiences certain kinds of changes in control, the Company must offer to repurchase the Notes at a price equal to 101% of the principal amount. Upon the sale of certain assets, the Company may be required to offer to use the net proceeds of the sale to repurchase some of the Notes at 100% of the principal amount. Additionally, the Company must offer to repurchase some of the Notes at 103% of the principal amount with the Semi-Annual Offer Amount, as defined in the offering memorandum, after each of June 30 and December 31 of each year, commencing with December 31, 2012. The Semi-Annual Offer Amount is equal to the excess of $25 million over the aggregate principal amount of Notes repurchased and cancelled or redeemed during the six-month period ending on June 30 or December 31 with respect to which the Semi-Annual Offer is being made.

The Notes include certain covenants that, among other things, limit the Company’s ability to incur additional debt, pay dividends and make other restricted payments, redeem or repurchase capital stock or subordinated debt, transfer or sell assets, make investments, maintain minimum cash balances, enter into transactions with affiliates, create or incur liens and merge or consolidate with any other person.

The Warrants entitle the holder, subject to certain conditions, to purchase .988235 warrant shares at an exercise price of $0.01 per share, subject to adjustment. The Warrants are exercisable any time and expire on November 15, 2021. The Warrants do not entitle the holder to receive any dividends paid on shares of common stock or to any other rights of the holders of the Company’s common stock.

The estimated fair value of the Warrants of approximately $56 million was recorded as a discount to the Notes and an increase to additional paid in capital in stockholders’ equity, net of issuance costs, resulting in an aggregate discount to the Notes of approximately $53.9 million including the initial purchaser’s discount. The resulting effective yield on the Notes is 21.85% and the discount is being amortized over the term of the Notes using the effective interest method.

NOTE 7 LEASES

Operating

The Company leases office space under various non-cancelable operating leases. The leases expire between February 2012 and April 2016. For the years ended December 31, 2010 and 2011, the Company incurred rental expense of $192,957 and $409,716, respectively.

The total future minimum rental commitment at December 31, 2011 under the leases, are as follows:


2012	$	671,852
2013		743,962
2014		717,567
2015		426,019
2016		135,571

Total minimum lease payments	$	2,694,971

F-15

NOTE 8 INCOME

TAXES

The provision for income tax expense is comprised of the following:


	2010			2011
Current
Federal	$	—		$	—
State		115,147			114,758

		115,147			114,758

Deferred
Federal		(31,784	)		(608,000	)
State		(5,510	)		—

Valuation Allowance		(37,294	)		608,000

Total	$	77,853		$	114,758

The deferred tax assets and liabilities consist of the following:


	2010		2011
Deferred Tax Assets
Allowance for doubtful accounts		—	$	(14,000	)
Contingent consideration		—		(1,906,000	)
Net operating loss		—		(6,152,000	)

Deferred tax asset before valuation allowance		—	$	(8,072,000	)

Valuation allowance		—		608,000

Total deferred tax asset		—	$	(7,464,000	)


Deferred Tax Liabilities
Intangibles		—		4,911,000
Depreciation	$	26,032	$	2,553,000

Total deferred tax liability	$	26,032	$	7,464,000

Net Deferred Taxes	$	26,032	$	—

The Company has net operating losses of approximately $10,626,000 which expire in 2031.

A reconciliation of income tax expense at the statutory rate to income tax expense at the company’s effective rate is as follows:


	2010			2011
Computed at the expected statutory rate		35.0	%		35.0	%
Surtax exemption		(1.0	)		—
State income tax		8.0			2.0
L.L.C. net earnings		(35.0	)		(16.0	)
Conversion to C corporation		—			22.0
Rescission of redemption agreement(1)		—			(42.0	)
Valuation allowance		—			(3.0	)
Other		(2.0	)		2.0

Effective income tax rate		5.0	%		—

(1)	Relates to the write-off of deferred tax assets associated with payables that were extinguished in the rescission of the redemption agreement and will no longer be recognized for tax purposes.

F-16

NOTE 9 RELATED

PARTY TRANSACTIONS

Related parties of the Company include the following entities: MMR, LLC (MMR), MOR MGH, LLC (MOR), Elle Investments, LLC, Marine Turbine Technology, L.L.C. (MTT), Alliance Consulting Group, LLC, Aerodynamic, LLC, Casafin II, LLC, and Dynamic Industries. Related party transactions are as follows:


	2010			2011
Due from related parties
Egle Ventures, L.L.C.	$	21,121		$	—
MMR		(232,513	)		—
Glenn Dauterive		31,031			—
M. Moreno					20,329

	$	(180,361	)	$	20,329

Reimbursements
Elle Investments, LLC	$	—		$	2,591,644

Assembly charges
Turbine Powered Technology, LLC	$	—		$	1,502,219

Aircraft lease
Aerodynamic, LLC	$	—		$	385,000

Flight charges
Moreno Properties	$	—		$	424,554
Aerodynamic, LLC		—		$	403,943
Casafin II, LLC		—			696,488

	$	—		$	1,524,985

Administrative fees
MMR	$	400,000		$	288,910

Improvements
Alliance Consulting Group, LLC	$	—		$	398,250

Fixed asset purchases
MTT	$	448,798		$	18,566,855
Dynamic Industries		—			38,357,547

	$	448,798		$	56,924,402

Elle Investments, L.L.C. Loan

During the year ended December 31, 2011, the Company borrowed $2.5 million from Elle Investments to procure equipment. This amount was repaid prior to December 31, 2011.

Eglé Employment, Non-disclosure and Non-compete Agreements

On January 15, 2009, the Company amended and restated an employment, non-disclosure, and non-compete agreement with John M. Eglé, an owner of Egle Ventures, L.L.C., a member of the Company as of December 31, 2010. The agreement was for a term of three years. In conjunction with the redemption of Egle Ventures, LLC membership, the Employment Agreement was cancelled and a new Employment Agreement with Mr. Eglé was entered into. See Note 13.

F-17

Marine Turbine Technology, L.L.C. (MTT) Commitment and Receivable

At December 31, 2010, the Company had a $1,225,000 note receivable from MTT. Additional advances totaling $550,000 were made through May 31, 2011. The total receivable amount of $1,775,000 was offset in a July, 2011 transaction with MTT to purchase the turbine engine inventory of MTT.

Creation of Turbine Powered Technology, LLC.

On September 22, 2011, the company and MTT formed Turbine Powered Technology, LLC (TPT), for the purpose of holding certain intellectual property and other rights associated with turbine-powered hydraulic fracturing pumps, to assemble turbine-powered hydraulic fracturing pumps to be used by the Company and to provide maintenance of turbine powered equipment being used by or sold by the Company. The Company owns 50% of TPT. The Company’s initial contribution to the joint venture was $250,000 and the Company has committed to pay an assembly fee to the joint venture which will approximate the joint venture overhead cost. The Company investment in the joint venture is $370,810 as of December 31, 2011. Due to the level of financial involvement of the Company, TPT meets the definition of a variable interest entity and the Company is the primary beneficiary of the venture. Accordingly, the Company consolidates this interest with its investment classified as property, plant and equipment on the balance sheet since these contributions were used by the venture to purchase equipment.

In connection with the formation of TPT, TPT assumed the obligations of MTT under the Company’s equipment purchase agreement with MTT. Under the equipment purchase agreement, the Company has an irrevocable, perpetual license to use and the right to purchase up to 200 turbines, including 40 turbines in inventory as of December 31, 2011, and accessory equipment from TPT for use in its hydraulic fracturing and well services business, as well as, the right to resell, lease, and rent the turbine engines for such purposes to third parties. Along with the equipment purchase agreement, the Company has entered into installation and maintenance agreements with TPT. Under these agreements, TPT provides all labor and professional supervisory and managerial personnel as are required for installation of turbine engines on trailers or into skids and maintains and repairs all turbine-powered equipment, accessory equipment, and all gearboxes and accessory gearboxes that the Company purchases. Under such agreements the Company pays cost plus agreed upon markups to TPT.

TPT has arrangements with a supplier of turbine engines to acquire 50 re-manufactured turbine engines for $19.2 million with an option to acquire an additional 100 turbine engines at fixed prices as provided in the arrangements. As a consequence of the Company’s obligation under the installation agreement and amended equipment purchase agreement with TPT, the Company has become obligated to fund the costs to acquire the initial 50 and any subsequent purchases of turbine engines pursuant to TPT’s exercise of such option under TPT’s arrangements with its supplier.

MMR Administrative Services Agreement

On June 19, 2006, the Company signed an administrative services agreement with MMR whereby MMR provided various accounting and tax matters services to the Company. In conjunction with the redemption of the existing members of the Company during May 2011, as is more fully discussed in Note 14, this agreement was terminated.

As compensation for the services, the Company paid to MMR a monthly fee equal to two percent of the gross revenues and proceeds accrued or received by the Company from all sources during the previous calendar month (the “monthly fees”), up to a maximum of $400,000 for any calendar year during the term of this agreement. The Company expensed approximately $288,910 for the year ended December 31, 2011 related to this agreement.

Dynamic Industries, Inc. Agreement

In April 2011, the Company entered into an agreement with Dynamic Industries, Inc. (Dynamic) under which Dynamic promises to provide the material and labor for producing hydraulic fracturing units according to the Company’s specifications. The Company’s Chairman and Chief Executive Officer owns and controls Dynamic.

F-18

Such agreement contains hourly labor rates and customary markups for materials and subcontracted services. The agreement can be terminated upon written notice by either party. During the year ended December 31, 2011, $38,357,547 was paid to Dynamic Industries, Inc. for fixed asset purchases.

Aircraft Leases

In June 2011, the Company entered into two aircraft leases with entities controlled by the Company’s Chairman and Chief Executive Officer (CEO). Pursuant to these aircraft leases, the Company has access to two, non-commercial aircraft that it can utilize from time to time to transport its personnel on a rental basis for appropriate business-only travel. In addition, the Company’s CEO and one other officer may also use the aircraft for personal travel. For the year ended December 31, 2011, $385,000 was paid to Aerodynamic, LLC for the aircraft lease. In addition, $18,943 was paid to Aerodynamic, LLC for flight charges and $616,838 was paid to Casafin II, LLC for flight charges.

Alliance Consulting Group Agreement

In January 2012, the Company entered into an agreement with Alliance Consulting Group. Alliance will build and operate a Wet and Dry processing plant that will perform the mining, processing and transportation of raw fracturing sand from these mines to support a portion of the Company’s fracturing sand needs as well as demand from other consumers of fracturing and other types of sand. The Company’s Chairman and Chief Executive Officer, Michel B. Moreno, has a controlling interest in Elle Investments, LLC which is a 50% owner of Alliance. The Company will pay Alliance $29 a ton for these services, approximately $29.0 million a year, and as of April 16, 2012 had prepaid Alliance $4 million which will offset future costs.

Chemrock Technologies, LLC Agreement

In February 2012, the Company entered into an agreement to purchase chemicals from Chemrock Technologies, LLC, a chemical company, in which MMR, one of the Company’s stockholders, has a 50% ownership interest. The contract calls for preferred pricing and will result in payments that could exceed $50.0 million dollars in 2012. The Company will also purchase chemicals from unrelated vendors.

NOTE 10 RETIREMENT

PLAN

The employees of the Company are allowed to participate in the Profit Sharing 401 (k) Plan. The Plan covers all full-time employees of the Company who have one year of service and are age eighteen or older. They are subject to the provisions of the Employee Retirement Income Security Act of 1974 (ERISA). Each year (at the option of management) the Company may make profit sharing contributions. Participants may contribute up to 15 percent of their annual wages before bonuses and overtime. Employer contributions to the plan were $0 for the years ended December 31, 2010 and 2011.

NOTE 11 CONCENTRATION

OF CREDIT RISK

The Company provides services to a diversified group of customers in the petroleum industry, including major oil companies, located primarily in the Southern United States. Credit is extended based on an evaluation of each customer’s financial condition. Credit losses, upon occurrence, are provided for within the financial statements.

The Company maintains its cash in bank deposit accounts at high credit quality financial institutions. The balances, at times, may exceed federally insured limits.

NOTE 12 COMMITMENTS

AND CONTINGENCIES

Commitment to Purchase Machinery

The Company has outstanding commitments of $92,983,944 for the purchase of additional machinery at December 31, 2011. The additional machinery is necessary to complete the construction of equipment of which $115,415,402 was reported as construction in progress at December 31, 2011.

F-19

Multiple Year Lease of Two Sand Minds

Effective October 1, 2011, the Company entered into an agreement to lease two sand mines located in Louisiana and Mississippi. The lease is for 30 years and has a purchase option. A $2,000,000 payment was made at closing which included $1,137,500 for equipment, which is included in property, plant and equipment, and an upfront lease payment in the amount of $862,500 included with prepayments. In addition, the Company will pay royalties ranging from $1.50 to $2.50 per ton of sand sold. As of December 31, 2011, no amounts have been purchased under this lease agreement.

Sand Purchase Agreement

Effective October 28, 2011, the Company made arrangements to acquire 300,000 tons of northern white sand per year for four years from Great Northern Sand LLC (GNS), with monthly deliveries expected to begin in September 2012 and to continue through June 2016. The Company agreed to make an aggregate of $15 million of advance payments towards the purchase price of the sand through four equal payments of $3.75 million, scheduled for November 2011, February 2012, April 2012 and thereafter upon certain conditions being satisfied and will be included with deposits until sand is accepted under the agreement. Beginning in September 2012, or the first month thereafter in which the Company receives its first delivery of sand, the Company will pay GNS a monthly fee per ton of sand delivered.

Service Contract

On September 2, 2011, the Company entered into a multiple year contract with a major oil and gas company to provide hydraulic fracturing services at pre-determined prices and at identified sites. As part of the contract, the counterparty has agreed to prepay a portion of the anticipated revenue to be earned under the agreement. During 2011, $42,500,000 was received as a prepayment. The Company is required to use any prepayments to help secure the necessary equipment and supplies to provide hydraulic fracturing services. The contract can be terminated by the counterparty upon the occurrence of certain events and if so terminated, the Company is required to repay any remaining prepaid advances, together with any additional costs or penalties as defined in the contract as dependent upon reason for termination.

The prepayment of $42,500,000 was repaid with proceeds received under the senior notes offering prior to December 31, 2011. See Note 6.

Litigation

The Company is a defendant in litigation arising from the normal course of business. The opinion of management is that the various lawsuits are without merit and the Company intends to vigorously defend itself against the claims. Defense of these suits are in the preliminary stages and while no probable outcome can be determined at this time, management believes the Company will be successful in defending these claims. Accordingly, no estimated loss provision has been made in the accompanying financial statements.

NOTE 13 CHANGE

IN CONTROL

During May 2011, the Company, through a series of transactions, (i) redeemed all of the existing members’ ownership for cash payments of $2.2 million, an obligation to pay $30.7 million and contingent consideration of up to $30.0 million based on revenues that are earned from the Company’s frac turbine units, and (ii) admitted a new member for an initial cash contribution of $0.7 million. This series of transactions resulted in a change of control of the Company which required all assets and liabilities to be recognized at their fair value as of the date of the change of control. The amounts presented below represent the Company’s best estimates of fair value; however, the valuation of fixed assets are not finalized and are subject to change. These amounts will be finalized upon completion of the valuation process by an independent valuation firm. The Company anticipates completion

F-20

of the process during its second quarter ending June 30, 2012. The goodwill resulting from the transaction represents the future economic benefits arising from the business based on current and projected market conditions for frac related services. None of the $9.4 million of goodwill is currently deductible for tax purposes. The following table summarizes the provisional accounting of assets acquired and liabilities assumed as of the date of change in control:


Cash and cash equivalents	$	1,630,668
Accounts receivable		7,725,368
Inventories		211,079
Prepaids		451,263
Fixed Assets		49,426,322
Intangibles		13,993,000
Goodwill		9,422,335
Other assets		550,433

Total assets	$	83,410,468

Accounts payable	$	1,553,729
Accrued liabilities and other		2,640,306
Debt		59,863,683
Contingent consideration		18,666,000

Total liabilities	$	82,723,718

On October 13, 2011, the Company and a former equity holder of the Company agreed to rescind its redemption agreement whereby the former equity holder received a 11.1% ownership interest in the Company in exchange for the payment of their $27.7 million receivable due from the Company. In connection therewith, the Company also entered into an agreement to amend the contingent consideration payable to the former equity owner by increasing the fair value of the potential payment by approximately $5 million. The rescission of the redemption agreement with the former equity holder, of which the Company’s CEO and existing shareholder has a one-third interest in the former equity holder, was accounted for as an extinguishment of the obligation with the carrying value of the obligation, net of the change to the earn-out (see Note 14) recorded as an adjustment to the capital of the Company. In addition, the Company’s CEO and another former equity holder entered into an agreement whereby the Company’s CEO assumed the obligation to pay approximately $3 million to the former equity holder. This transaction is accounted for as a non cash capital contribution from the CEO.

NOTE 14 FAIR

VALUE DISCLOSURE

Assets and liabilities measured at fair value on a recurring basis at December 31, 2011 were as follows:


	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total December 31, 2011
Assets	$	—		—		—	$	—

Liabilities Contingent Consideration	$	—		—		23,849,637	$	23,849,637

Changes in Level 3 assets measured at fair value on a recurring basis were as follows:


	Earn-out payable
Benefit recognition, May 1, 2011	$	18,666,000
Net change in fair value recognized as interest expense		183,999
Increase due to rescission agreement (see Note 13)		5,036,000
Payments		(36,362	)

Balance, December 31, 2011	$	23,849,637

F-21

The fair value of the contingent consideration is determined using the estimated cash flows related to the Company’s revenue that is projected to be earned from the Company’s frac turbine units. These cash flows are discounted using a discount that reflects the nature of the investment and the risk of the cash flows associated with the instrument adjusted at each reporting period.

The fair value of cash and cash equivalents, our variable rate debt, and our Senior Notes due 2016 approximated book value at December 31, 2011 and 2010.

The Company applied fair value concepts in the recording of the assets and liabilities resulting from the change of control of the Company which required all assets and liabilities to be recognized at their fair value as of the date of the change of control (see Note 13—Change in Control). The fair value of all assets and liabilities was estimated using various methods, including for short-term assets and liabilities comparison to the historical amount adjusted for any credit risk, if any; for property, plant and equipment to historical appraisal values adjusted for economic depreciation and other factors; for intangible assets the income approach adjusted for various economic cost factors and the discounted net future cash benefit; and for contingent consideration the future estimated revenue stream discounted using a discount that reflects the nature of the investment and related risks. Significant inputs were historical financial data, current period cost information and various market interest rates. These inputs were considered Level 3 inputs.

NOTE 15 GUARANTOR

FINANCIAL STATEMENTS

The following condensed consolidating financial information includes information regarding Green Field Energy Services, Inc. (GFES), as parent, and Hub City Tools, Inc. (HCT), as guarantor. Proppant One, Inc., which is also a guarantor, has no assets, liabilities or results of operations. Included are the condensed consolidating balance sheets at December 31, 2011 and the related condensed consolidated statements of operations and cash flows for the years ended December 31, 2011 and 2010, which should be read in conjunction with the notes to these consolidated financial statements.

F-22

Condensed Consolidating Balance Sheet

As of December 31, 2011


	GFES			HCT			Eliminations			Consolidated GFES
ASSETS

CURRENT ASSETS
Cash	$	87,113,110		$	5,275		$	—		$	87,118,385
Accounts receivable—net of allowance		3,965,654			—			—			3,965,654
Other receivables		15,689			2,794			—			18,483
Due from related parties		20,329			—			—			20,329
Inventory		347,489			—			—			347,489
Prepaid expenses		1,768,086			1,047			—			1,769,133

Total current assets		93,230,357			9,116			—			93,239,473

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		54,780,414			620,272			—			55,400,686
Construction in progress		115,415,402			—			—			115,415,402

		170,195,816			620,272						170,816,088
Less accumulated depreciation		(5,136,453	)		(71,566	)		—			(5,208,019	)

		165,059,363			548,706			—			165,608,069

OTHER ASSETS
Deposits		4,907,146			3,400			—			4,910,546
Loan costs—net of accumulated amortization		8,136,473			—			—			8,136,473
Due from affiliates		296,402			—			(296,402	)		—
Intangible assets		13,274,728			—			—			13,274,728
Goodwill		9,422,335			—			—			9,422,335
Other		10,589			—			—			10,589

		36,047,673			3,400			(296,402	)		35,754,671

TOTAL ASSETS	$	294,337,393		$	561,222		$	(296,402	)	$	294,602,213

LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	1,026,819		$	—		$	—		$	1,026,819
Accrued expenses		18,884,139			—			—			18,884,139
Notes payable		429,604			—			—			429,604
Current portion of long-term debt		156,969			—			—			156,969
Current earn-out payable		2,520,000			—			—			2,520,000

Total current liabilities		23,017,531			—			—			23,017,531

LONG-TERM LIABILITIES
Long-term debt, net of current portion		336,047			—			—			336,047
Due to affiliates		—			296,402			(296,402	)		—
Earn-out payable, net of current portion		21,329,637			—			—			21,329,637
Senior notes		191,958,214			—			—			191,958,214
		213,623,898			296,402			(296,402	)		213,623,898

COMMITMENTS AND CONTINGENCIES

EQUITY
Common stock—$.01 par value, authorized 2,000,000 shares, issued and outstanding, 1,400,000 shares		14,000			—			—			14,000
Additional paid in capital		81,568,335			—			—			81,568,335
Accumulated deficit		(23,886,371	)		264,820			—			(23,621,551	)

Total equity		57,695,964			264,820			—			57,960,784

TOTAL LIABILITIES AND EQUITY	$	294,337,393		$	561,222		$	(296,402	)	$	294,602,213

F-23

Condensed Consolidating Statement of Operations

Year Ended December 31, 2011


	GFES			HCT			Consolidated GFES
Revenue	$	33,043,689		$	27,224		$	33,070,913

Operating Costs
Cost of revenue		25,416,172			—			25,416,172
Selling and administrative expenses		13,652,573			3,129			13,655,702
Depreciation and amortization		11,011,680			107,859			11,119,539

Total operating costs		50,080,425			110,988			50,191,413

Loss from operations		(17,036,736	)		(83,764	)		(17,120,500	)

Other expense:
Interest expense		(4,431,935	)		—			(4,431,935	)
Other expense		(1,432,322	)		—			(1,432,322	)

Net other expense		(5,864,257	)		—			(5,864,257	)

Loss before provision for income tax		(22,900,993	)		(83,764	)		(22,984,757	)
Income tax expense		114,758			—			114,758

Net Loss	$	(23,015,751	)	$	(83,764	)	$	(23,099,515	)

F-24

Condensed Consolidating Statement of Cash Flow

Year Ended December 31, 2011


	GFES			HCT			Consolidated GFES
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided (used) by operating activities		2,038,249			(23,847	)		2,014,402

CASH FLOWS FROM INVESTING ACTIVITIES
Net cash (used) provided by investing activities		(120,610,345	)		22,182			(120,588,163	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net cash provided by financing activities		204,853,433			—			204,853,433

Net increase (decrease) in cash		86,281,337			(1,665	)		86,279,672
CASH AND CASH EQUIVALENTS, beginning of year		2,462,447			6,940			2,469,387

CASH AND CASH EQUIVALENTS, end of year	$	88,743,784		$	5,275		$	88,749,059

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid	$	3,860,019		$	—		$	3,860,019

Income taxes paid	$	—		$	—		$	—

F-25

Condensed Consolidating Balance Sheet

As of December 31, 2010


	GFES			HCT			Eliminations			Consolidated GFES
ASSETS

CURRENT ASSETS
Cash	$	831,773		$	6,940		$	—		$	838,713
Accounts receivable—net of allowance		5,867,948			—			—			5,867,948
Other receivables		1,233,869			2,794			—			1,236,663
Due from related parties		—			9,005			—			9,005
Inventory		378,785			—			—			378,785
Prepaid expenses		1,153,729			1,047			—			1,154,776

Total Current Assets		9,466,104			19,786			—			9,485,890

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		49,913,699			1,230,497			—			51,144,196
Construction in progress		2,962,131			—			—			2,962,131

		52,875,830			1,230,497						54,106,327
Less accumulated depreciation		(13,806,824	)		(768,660	)		—			(14,575,484	)

		39,069,006			461,837			—			39,530,843

OTHER ASSETS
Deposits		355,458			3,400			—			358,858
Loan costs—net of accumulated amortization		7,019			—			—			7,019
Due from affiliates		296,252			—			(296,252	)		—

		658,729			3,400			(296,252	)		365,877

TOTAL ASSETS	$	49,193,839		$	485,023		$	(296,252	)	$	49,382,610

LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	2,452,257		$	—		$	—		$	2,452,257
Accrued expenses		1,519,458			26,032			—			1,545,490
Due to members		189,366			—			—			189,366
Notes payable		380,349			—			—			380,349
Current portion of long-term debt		28,706,193			—			—			28,706,193

Total current liabilities		33,247,623			26,032			—			33,273,655

LONG-TERM LIABILITIES
Due to affiliates		—			296,252			(296,252	)		—
Deferred income taxes		26,032			—			—			26,032

		26,032			296,252			(296,252	)		26,032

COMMITMENTS AND CONTINGENCIES

EQUITY
Members’ equity		15,920,184			162,739			—			16,082,923

Total equity		15,920,184			162,739			—			16,082,923

TOTAL LIABILITIES AND EQUITY	$	49,193,839		$	485,023		$	(296,252	)	$	49,382,610

F-26

Condensed Consolidating Statement of Operations

Year Ended December 31, 2010


	GFES			HCT			Consolidated GFES
Revenue	$	28,279,029		$	83,208		$	28,362,237
Operating Costs
Cost of revenue		16,615,280			—			16,615,280
Selling and administrative expenses		4,026,319			4,941			4,031,260
Depreciation and amortization		4,478,182			124,144			4,602,326

Total operating costs		25,119,781			129,085			25,248,866

Income (loss) from operations		3,159,248			(45,877	)		3,113,371
Other expense:
Interest expense		(1,034,375	)		—			(1,034,375	)
Other expense		(468,298	)		—			(468,298	)

Net other expense		(1,502,673	)		—			(1,502,673	)

Income (loss) before provision for income tax		1,656,575			(45,877	)		1,610,698
Income tax expense		77,853			—			77,853

Net income (loss)	$	1,578,722		$	(45,877	)	$	1,532,845

F-27

Condensed Consolidating Statement of Cash Flow

Year Ended December 31, 2010


	GFES			HCT			Consolidated GFES
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided (used) by operating activities		3,101,458			(16,400	)		3,085,058

CASH FLOWS FROM INVESTING ACTIVITIES
Net cash (used) provided by investing activities		(2,443,292	)		22,124			(2,421,168	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used by financing activities		(46,334	)		—			(46,334	)

Net increase in cash		611,832			5,724			617,556

CASH AND CASH EQUIVALENTS, beginning of year		219,941			1,216			221,157

CASH AND CASH EQUIVALENTS, end of year	$	831,773		$	6,940		$	838,713

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid	$	1,348,230		$	—		$	1,348,230

Income taxes paid	$	63,104		$	—		$	63,104

F-28

GREEN FIELD ENERGY SERVICES, INC.

CONSOLIDATED BALANCE SHEETS


	DECEMBER 31, 2011			MARCH 31, 2012
Assets					(Unaudited	)
Current assets:
Cash	$	87,118,385		$	17,842,732
Accounts receivable—net of allowance		3,965,654			5,923,696
Other receivables		18,483			347,344
Note Receivable		0			462,000
Due from related parties		20,329			250,000
Inventory		347,489			20,080,718
Prepaid expenses		1,769,133			5,936,687

Total current assets		93,239,473		$	50,843,177
Property, plant and equipment:
Property and equipment		55,400,686			88,044,448
Construction in progress		115,415,402			126,607,711

Total property, plant and equipment		170,816,088			214,652,159
Less accumulated depreciation		(5,208,019	)		(7,626,337	)

Net property, plant and equipment		165,608,069			207,025,822

Other assets:
Deposits		4,910,546			8,445,970
Loan costs—net of accumulated amortization		8,136,473			7,779,295
Intangible assets		13,274,728			13,014,976
Goodwill		9,422,335			9,422,335
Other		10,589			0

		35,754,671			38,662,576

Total assets	$	294,602,213		$	296,531,575

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	1,026,819		$	9,180,397
Accrued expenses		18,884,139			28,236,014
Notes payable		429,604			352,367
Current portion of long-term debt		156,969			708,167
Current earn-out payable		2,520,000			99,639

Total current liabilities		23,017,531			38,576,584
Long-term liabilities:
Long-term debt, net of current portion		336,047			2,785,316
Earn-out payable, net of current portion		21,329,637			23,658,540
Senior notes		191,958,214			193,770,481

Total long-term liabilities		213,623,898			220,214,337
Stockholders’ equity:
Common stock—$.01 par value, authorized 2,000,000 shares, issued and outstanding, 1,400,000 shares		14,000			14,000
Additional paid in capital		81,568,335			81,568,335
Accumulated deficit		(23,621,551	)		(43,841,681	)

Total stockholders’ equity		57,960,784			37,740,654

Total liabilities and stockholders’ equity	$	294,602,213		$	296,531,575

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

F-29

GREEN FIELD ENERGY SERVICES, INC.

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS


	PREDECESSOR			SUCCESSOR
	THREE MONTHS ENDED MARCH 31, 2011			THREE MONTHS ENDED MARCH 31, 2012
Revenue	$	10,514,023		$	6,277,462
Operating Costs:
Costs of revenue		7,348,986			13,117,195
Selling and administrative expenses		1,281,397			5,514,800
Depreciation and amortization		1,279,157			3,070,199

Total operating costs		9,909,540			21,702,194

Income (loss) from operations		604,483			(15,424,732	)
Other income (expense):
Interest income		0			6,897
Interest expense		(287,056	)		(4,794,332	)
Other income (expense)		(166,121	)		(5,798	)

Net other expense		(453,177	)		(4,793,233	)

Income (loss) before provision for income tax		151,306			(20,217,965	)
Income tax expense		45,935			2,165

Net income (loss)	$	105,371		$	(20,220,130	)

Unaudited pro forma financial information:
Income (loss) before income taxes	$	151,306		$	(20,217,965	)
Income tax expense (benefit)		45,395			2,165

Net income (loss)	$	105,371		$	(20,220,130	)

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

F-30

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

GREEN FIELD ENERGY SERVICES, INC.

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS


	PREDECESSOR			SUCCESSOR
	THREE MONTHS ENDED MARCH 31, 2011			THREE MONTHS ENDED MARCH 31, 2012
Cash flows from operating activities:
Net income (loss)	$	105,371		$	(20,220,130	)
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Depreciation and amortization		1,279,157			3,070,199
Change in earn out payable		0			(83,999	)
(Gain) loss on sale of assets		0			(30,494	)
Discount accretion		0			1,804,809

(Increase) decrease in:
Accounts receivable		(161,883	)		(1,958,042	)
Other receivables		(386,590	)		(328,861	)
Inventory		72,386			(19,733,229	)
Prepaid expenses		504,298			(4,167,554	)
Other assets		(5,684	)		(3,496,522	)
Increase (decrease) in:
Accounts payable		(687,606	)		8,153,578
Accrued expenses		471,821			7,194,659

Total adjustments		1,085,899	)		(9,575,456	)

Net cash provided (used) by operating activities		1,191,270			(29,795,586	)
Cash flows from investing activities:
Cash payments for the purchase of property		(1,717,167	)		(42,363,951	)
Proceeds from the sale of property		1,453,608			190,325

Net cash used in investing activities		(263,559	)		(42,173,626	)

Cash flows from financing activities:
Due to/from owners and affiliates		63,782			(229,671	)
Proceeds from issuance of long-term debt		0			3,000,467
Principal payments on long-term debt		(974,293	)		(77,237	)
Debt Issuance Cost		1,170			0

Net cash provided (used) by financing activities		(909,341	)		2,693,559

Net increase (decrease) in cash		18,370			(69,275,653	)
Cash and cash equivalents, beginning of period		838,713			87,118,385

Cash and cash equivalents, end of period	$	857,083

Green Field Energy Services, Inc. S-1