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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on September 10, 2010.

Registration No.              

UNITED STATES
Securities and Exchange Commission
Washington, D.C. 20549



FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



AVENTINE RENEWABLE ENERGY HOLDINGS, INC.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  2869
(Primary Standard Industrial
Classification Code Number)
  05-0569368
(I.R.S. Employer
Identification No.)



120 North Parkway Drive
Pekin, IL 61554
(309) 347-9200

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



Thomas L. Manuel
Chief Executive Officer
Aventine Renewable Energy Holdings, Inc.
120 North Parkway Drive
Pekin, IL 61554
(309) 347-9200

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



Copies to:

Ackneil M. Muldrow, III
Akin Gump Strauss Hauer & Feld LLP
One Bryant Park
New York, NY 10036
(212) 872-1000
(212) 872-1002 (fax)

 

Patrick J. Hurley
Akin Gump Strauss Hauer & Feld LLP
1111 Louisiana Street, Suite 4400
Houston, TX 77002
(713) 220-5800
(713) 236-0822 (fax)



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



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

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

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

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

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

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

CALCULATION OF REGISTRATION FEE

               
 
Title of each class of securities
to be registered

  Amount to be
registered

  Proposed Maximum
offering price per
share(1)

  Proposed Maximum
Aggregate Offering
Price(1)

  Amount of
Registration Fee

 

Common stock, par value $0.001 per share

  5,215,523   $22.50   $117,349,268   $8,367

 

(1)
Estimated solely for the purpose of calculating the registration fee under Rule 457(c) under the Securities Act. Calculated on the basis of the average of the highest and lowest sale price of the common stock on September 7, 2010.



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


Table of Contents

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

SUBJECT TO COMPLETION, DATED SEPTEMBER 10, 2010

Prospectus

5,215,523 Shares

LOGO

Common Stock



        Aventine Renewable Energy Holdings, Inc., a Delaware corporation, is a leading producer of corn-based fuel-grade ethanol in the United States, with production facilities in Illinois and Nebraska.

        This prospectus relates to up to 5,215,523 shares of our common stock which may be offered for sale by the selling stockholders named in this prospectus or in a supplement hereto. The selling stockholders acquired or (in the case of clause (ii)) acquired or may acquire (i) 1,710,000 shares of common stock offered by this prospectus in our private offering of 13% senior secured notes and common stock that closed on March 15, 2010 and (ii) up to 3,505,523 shares of common stock offered by this prospectus in distributions pursuant to 1145(b) under the Bankruptcy Code, in each case in connection with our plan of reorganization that became effective on March 15, 2010. We are registering the offer and sale of the shares of common stock to satisfy registration rights we have granted.

        We are not selling any shares of common stock under this prospectus and will not receive any proceeds from the sale of common stock by the selling stockholders. The shares of common stock to which this prospectus relates may be offered and sold from time to time directly from the selling stockholders or alternatively through underwriters or broker dealers or agents. The shares of common stock may be sold in one or more transactions, at fixed prices, at prevailing market prices at the time of sale or at negotiated prices. Please read "Plan of Distribution."

        Our common stock is quoted on the Over the Counter Bulletin Board under the symbol "AVRW.OB." The last reported sales price of our common stock on the Over the Counter Bulletin Board on September 7, 2010 was $22.50 per share.



        Investing in our common stock involves risks. See "Risk Factors" beginning on page 11 of this prospectus for some risks regarding an investment in our common stock.



        You should rely only on the information contained in this prospectus or any prospectus supplement or amendment. We have not authorized anyone to provide you with different information. We and the selling stockholders are not making an offer of these securities in any state where the offer is not permitted.

        Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is                    ,          .


Table of Contents


TABLE OF CONTENTS

INDUSTRY AND MARKET INFORMATION AND FORECASTS

  i

AVAILABLE INFORMATION

  i

FINANCIAL INFORMATION

  i

FORWARD LOOKING STATEMENTS

  ii

SUMMARY

  1

RISK FACTORS

  11

USE OF PROCEEDS

  26

DIVIDEND POLICY

  26

CAPITALIZATION

  27

MARKET FOR OUR COMMON STOCK

  28

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

  29

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

  31

BUSINESS

  58

MANAGEMENT

  77

EXECUTIVE COMPENSATION DISCUSSION AND ANALYSIS

  84

PRINCIPAL STOCKHOLDERS

  100

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

  103

SELLING STOCKHOLDERS

  105

SHARES ELIGIBLE FOR FUTURE SALE

  121

DESCRIPTION OF CAPITAL STOCK

  124

MATERIAL UNITED STATES FEDERAL TAX CONSIDERATIONS

  131

PLAN OF DISTRIBUTION

  133

LEGAL MATTERS

  136

EXPERTS

  136

INDEX TO FINANCIAL STATEMENTS

  F-1

Table of Contents


INDUSTRY AND MARKET INFORMATION AND FORECASTS

        We obtained the industry, market and competitive position data and forecasts used throughout this prospectus from our own research, internal surveys and surveys or studies conducted by third parties, independent industry or general publications and other publicly available information. In particular, we have based much of our discussion of the ethanol industry, including government regulation relevant to the industry and forecasted growth in demand, on information published by the Renewable Fuels Association ("RFA"), the national trade association for the United States ("U.S.") ethanol industry. Independent 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. Further, because the RFA is a trade organization for the ethanol industry, it may present information in a manner that is more favorable to the ethanol industry than would be presented by an independent source. While we believe that each of these studies and publications is reliable, we have not independently verified such data. Forecasts are particularly likely to be inaccurate, especially over long periods of time. For example, in 1983, the U.S. Department of Energy forecast that oil would cost $75 per barrel in 1995. In 1995, however, the price of oil was actually $17 per barrel. Similarly, we believe our internal research is reliable, but it has not been verified by any independent sources.




AVAILABLE INFORMATION

        We have filed with the Securities and Exchange Commission (the "SEC"), under the Securities Act of 1933, as amended (the "Securities Act"), a registration statement on Form S-1 with respect to the common stock offered by this prospectus. In addition, we file annual, quarterly and current reports, proxy statements and other information with the SEC. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement or the exhibits and schedules which are part of the registration statement, portions of which are omitted as permitted by the rules and regulations of the SEC. Statements made in this prospectus regarding the contents of any contract or other documents are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. For further information pertaining to us and to the common stock offered by this prospectus, reference is made to the registration statement, including the exhibits and schedules thereto, copies of which, together with all other reports, proxy statements and other information we file with the SEC, may be inspected without charge at the public reference facilities at the SEC at 100 F Street, NE, Washington, D.C. 20549. Copies of all or any portion of the registration statement and such other reports, proxy statements and other information may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website that contains reports, proxy and information statements and other information that is filed electronically with the SEC. The web site can be accessed at www.sec.gov.

        Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are available on our website, at no charge, at www.aventinerei.com, as soon as reasonably practicable after electronic filing or furnishing such information to the SEC. Information on our website, and in any other reports, proxy statements or other filed information not part of this prospectus, should not be considered to be part of this prospectus.




FINANCIAL INFORMATION

        As a result of the consummation of our plan of reorganization, on February 28, 2010, we adopted fresh-start accounting in accordance with Accounting Standards Codification Section 852, Reorganizations ("ASC 852"). Accordingly, the financial information on or prior to February 28, 2010 is not comparable with the financial information for periods after February 28, 2010.

i


Table of Contents


FORWARD LOOKING STATEMENTS

        All statements, other than statements of historical facts, included in this prospectus, are forward looking statements. In particular, statements that we make under the headings "Summary," "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," and "Business" relating to our overall volume trends, industry trends and forces, margin trends, anticipated capital expenditures, acquisitions, plant openings and our strategies are forward looking statements. When used in this document, the words "believe," "expect," "anticipate," "estimate," "project," "plan," "should," "would," "could" and similar expressions are intended to identify forward looking statements.

        These statements are based on assumptions and assessments made by our management in light of their experience and their perception of historical trends, current conditions, expected future developments and other factors they believe to be appropriate. Any forward looking statements are not guarantees of our future performance and are subject to risks and uncertainties that could cause actual results, developments and business decisions to differ materially from those contemplated by such forward looking statements. We disclaim any duty to update any forward looking statements. Some of the factors that may cause actual results, developments and business decisions to differ materially from those contemplated by such forward looking statements include the risk factors discussed under the heading "Risk Factors" and the following:

    our ability to obtain and maintain normal terms with vendors and service providers;

    our estimates of allowed general unsecured claims, unliquidated and contingent claims and estimations of future distributions of securities and allocations of securities among various categories of claim holders;

    our ability to maintain contracts that are critical to our operations;

    our ability to attract and retain customers;

    our ability to fund and execute our business plan and any acquisitions, ethanol plant expansion or construction projects;

    our ability to receive or renew permits to construct or commence operations of our proposed capacity additions in a timely manner, or at all;

    laws, tariffs, trade or other controls or enforcement practices applicable to our operations;

    changes in weather and general economic conditions;

    overcapacity within the ethanol, biodiesel and petroleum refining industries;

    availability and costs of products and raw materials, particularly corn, coal and natural gas and the subsequent impact on margins;

    our ability to raise additional capital and secure additional financing, and our ability to service our debt or comply with our debt covenants;

    our ability to attract, motivate and retain key employees;

    liability resulting from actual or potential future litigation; and

    plant shutdowns or disruptions.

ii


Table of Contents


SUMMARY

        This summary highlights information contained elsewhere in this prospectus. It does not contain all the information that you may consider important in making your investment decision. Therefore, you should read the entire prospectus carefully, including, in particular, the "Risk Factors" section and the consolidated financial statements and related notes appearing at the back of this prospectus.

        As used in this prospectus, unless the context otherwise requires or indicates, references to "Aventine," "Aventine Renewable Energy Holdings, Inc.," "Company," "we," "our," and "us," refer to Aventine Renewable Energy Holdings, Inc., and its subsidiaries, pro forma for this offering of common stock.


Business Overview

        We are a producer and marketer of corn-based fuel-grade ethanol in the U.S. We market and distribute ethanol to many of the leading energy and trading companies in the U.S. We produced 94.0 million gallons, 197.5 million gallons and 188.8 million gallons of ethanol in the six months ended June 30, 2010 and the years ended December 31, 2009 and 2008, respectively. In addition to producing ethanol, our facilities also produce several by-products, such as distillers grain, corn gluten meal and feed, corn germ and brewers' yeast, which generate revenue and allow us to help offset a significant portion of our corn costs. Historically, we have also been a large marketer of ethanol, distributing ethanol purchased from other third party producers in addition to our own ethanol production. In the six months ended June 30, 2010 and years ended December 31, 2009 and 2008, we distributed 0.7 million gallons, 66.4 million gallons and 754.3 million gallons, respectively, of ethanol produced by others. The decrease in distributed gallons from third party producers is attributable to the termination of our marketing alliance and substantial reduction in our purchase/resale supply operations in late 2008 and the first quarter of 2009. Our revenue and operating income (loss) for the six months ended June 30, 2010 were $211.6 million and $(9.0) million, respectively, and for the years ended December 31, 2009 and 2008 were $594.6 million and $(19.5) million and $2.2 billion and $(34.9) million, respectively.

        We derive our revenue primarily from the sale of ethanol. For the six months ended June 30, 2010 and the years ended December 31, 2009, 2008 and 2007 we generated approximately $164.7 million, $349.4 million, $417.6 million and $399.6 million of revenue, respectively, from the sale of ethanol produced at our facilities. We also derive revenue from the sale of co-products and bio-products which are produced as by-products during the production of ethanol at our plants. For the six months ended June 30, 2010 and the years ended December 31, 2009, 2008 and 2007, we generated approximately $46.9 million, $98.0 million, $128.5 million and $99.3 million, respectively, of revenue from the sale of co-products and bio-products, allowing us to recapture approximately 36.6%, 34.1%, 35.9% and 36.7% of our corn costs, respectively, in such six month period and each of these years.

        We market and sell ethanol without regard to the source of origination. With our own (or equity) production combined with ethanol sourced from third parties (or non-equity production), we marketed and distributed 95.6 million, 277.5 million, 936.0 million and 690.2 million gallons of ethanol for the six months ended June 30, 2010 and the years ended December 31, 2009, 2008 and 2007, respectively. Because of the challenges facing the ethanol industry in general and us in particular, we sharply decreased the number of gallons of ethanol we sold that were produced by third parties in 2009 by terminating our marketing alliance and significantly reducing our purchase/resale operations. We generated approximately $1.2 million of revenue from sales of gallons sourced from our marketing alliance and purchase and resale operations in the six months ended June 30, 2010, and $111.5 million, $1.7 billion and $1.1 billion, respectively, in the years ended December 31, 2009, 2008 and 2007.

        Equity Ethanol Production.    We own and operate one of the few coal-fired, corn wet mill plants in the U.S. in Pekin, Illinois, which we refer to as the "Illinois wet mill facility." In addition, we own and operate a natural gas-fired corn dry mill plant in Pekin, Illinois which we refer to as the "Illinois dry

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mill facility," and a natural gas-fired corn dry mill plant in Aurora, Nebraska, which we refer to as the "Nebraska facility." We refer to our Illinois dry mill and wet mill facilities collectively as our "Illinois facilities." Further, in August 2010 we acquired a 38 million gallon undenatured annualized capacity ethanol production facility in Canton, Illinois, which we refer to as the "Canton facility."

        Our Illinois dry mill facility was completed in early 2007. The addition of this facility increased our total annual production capacity by approximately 57 million gallons. For each of the years ended December 31, 2009, 2008 and 2007, our facilities had a combined total ethanol production capacity of approximately 200 million gallons annually with corn processing capacity of approximately 77 million bushels per year at capacity. Our plants ran at 98% of capacity for 2009 and at 94% of capacity for both 2008 and 2007, after adjusting for differences in denaturant blending levels.

        By-Products.    We generate additional revenue through the sale of by-products (both co-products and bio-products, which we sometimes refer to collectively as either by-products or co-products) that result from the ethanol production process. These by-products include brewers' yeast, corn gluten feed and meal, corn germ, condensed corn distillers with solubles ("CCDS"), carbon dioxide, dried distillers grain with solubles ("DDGS") and wet distillers grains with solubles ("WDGS").

        Purchase/Resale.    Historically, we have also purchased ethanol from unaffiliated third-party producers and marketers on both a spot basis and under contract. These transactions were driven by our ability to purchase ethanol and then, through our distribution network and customer relationships, resell the ethanol. For the years ended December 31, 2008 and 2007, we purchased for resale 249.0 million and 111.5 million gallons of ethanol, respectively, from unaffiliated producers and marketers. We began a program to rationalize our distribution network and reduce our sourcing of ethanol from third parties in late 2008. Our purchase/resale program was part of this rationalization process. Accordingly, we only purchased 0.7 million and 35.5 million gallons of ethanol for resale from unaffiliated producers and marketers during the six months ended June 30, 2010 and the year ended December 31, 2009, respectively.


Industry Overview

        Ethanol is marketed across the U.S. as a gasoline blend component that serves as a clean air additive, an octane enhancer and a renewable fuel resource. It is blended with gasoline (i) as an oxygenate to help meet fuel emission standards, (ii) to improve gasoline performance by increasing octane levels and (iii) to extend fuel supplies. A small but growing amount of ethanol is also used as E85, a renewable fuels-driven blend comprised of up to 85% ethanol.

        Ethanol is generally sold through short-term contracts. Although ethanol has in the past generally been priced at either a negotiated fixed price or a price based upon the price of wholesale gasoline plus or minus a fixed amount, the majority of ethanol sold in the U.S. today is based upon a spot index price at the time of shipment. The price of ethanol has historically moved in relation to the price of wholesale gasoline and the value of the Volumetric Ethanol Excise Tax Credit ("VEETC"). However, the price of ethanol over the last three years has been largely driven by supply/demand fundamentals and the price of corn.

        According to recent industry reports, approximately 99.4% of domestic ethanol is produced from corn fermentation as of December 31, 2009 and is primarily produced in the Midwestern corn-growing states. The principal factor affecting the cost to produce ethanol is the price of corn.

        The U.S. fuel ethanol industry has experienced rapid growth, increasing from 1.4 billion gallons of production in 1998 to approximately 10.8 billion gallons produced in 2009, the latest year for which production information is available. The RFA reports that the U.S. fuel ethanol industry has 187 operating plants and approximately 13.0 billion gallons of annual production capacity (including idled capacity) as of January 2010.

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Competitive Strengths

        We believe that our competitive strengths include the following:

    Strong Market Position.  We are a leading producer and marketer of ethanol in the U.S. based on both gallons of ethanol produced and sold. For the year ended December 31, 2009, we produced 197.5 million gallons, sold 66.4 million gallons of ethanol from non equity production, and reduced our ethanol inventory by 13.6 million gallons for a total sales volume of 277.5 million gallons.

    Diversified Supply Base.  Our facilities are diversified across geography, fuel source and technology, allowing us to capitalize on multiple opportunities and limit our exposure to any one input. We also generate revenue from multiple sources—equity (or produced), non-equity (or marketed but not produced) and co-products (or from our production).

    Supplier of Choice.  We maintain long-standing customer relationships with most of the major integrated oil refiners operating in North America (including Royal Dutch Shell and its affiliates, Conoco Phillips Company, Valero Marketing and Supply Company, and Chevron Corporation) due to our ability to distribute ethanol extensively.

    Low Cost Producer.  We believe we are one of the lowest cost producers of ethanol in the U.S. Our Illinois wet mill facility generates 38% of its own electricity and its remaining energy needs are met by using lower cost coal, which provides us significant cost savings compared to ethanol facilities that use higher cost natural gas to generate power. In addition, our Illinois wet mill facility, through its wet mill production process, generates higher margin co-products and bio-products, which allowed us to recapture 42.7% of our total corn cost of such facility in the year ended December 31, 2009, which is a higher percentage than our competitors who employ the dry mill production process. At our Illinois dry mill facility and our Nebraska facility which employs the dry mill process, we recaptured 26.7% and 24.5% of our total corn costs, respectively, in the year ended December 31, 2009.

    Experienced and Proven Management Team.  Our management team has a combined 64 years of experience in the ethanol production industry. Our Chief Executive Officer, Thomas Manuel, was previously the President and Chief Executive Officer of ASAlliances Biofuels LLC and has 40 years experience in managing commodity-related businesses. John Castle, our Chief Financial Officer, was previously the Senior Vice President of Operations and Chief Financial Officer of White Energy, Inc. an ethanol production company.


Business and Growth Strategy

        We are pursuing the following business and growth strategies:

    Add Production Capacity to Meet Expected Demand for Ethanol.  We have identified opportunities to increase our equity production capacity through the development of new production facilities and are continually exploring acquisition opportunities. We are currently building 110 million gallon undenatured annualized capacity ethanol production facilities at both Mt. Vernon, Indiana and Aurora, Nebraska, which we expect to complete in the fourth quarter of 2010, and in August 2010 we acquired the Canton facility, which we expect to become operational in the second quarter of 2011. After giving effect to the completion of these projects, our expected ethanol production capacity will be approximately 460 million gallons per year.

    Capitalize on Current and Changing Regulation.  Through continued investment in increasing production capacity, we believe we are well positioned to take advantage of the current and changing regulatory environment in our industry. For example, the Energy Independence and Security Act of 2007 ("EISA") increased the mandated minimum use of renewable fuels to

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      9 billion gallons in 2008 (up from a 5.4 billion gallon requirement, which was the previous mandated 2008 requirement under the Energy Policy Act of 2005). The mandated usage of renewable fuels increases to 36 billion gallons in 2022. The upper mandate for corn based ethanol is 15 billion gallons by 2015.

    Entry into new and diversified markets.  We are continually negotiating additional sales agreements. We persistently strive to enhance and optimize our multiple modes of transportation and sources of production. In addition, as numerous countries in Europe, Asia and South America have increased the mandated use of renewable fuels, we believe that there are burgeoning export opportunities for our ethanol and by products.

    Transform from Ethanol Seller to Risk Manager.  We apply risk mitigation and management techniques used for decades by well-established agricultural processing businesses such as ConAgra Foods, Cargill and Archer Daniels Midland. Combined with the termination of our marketing alliance and reduction in purchase/resale supply operations in late 2008 and the first quarter of 2009, we now focus primarily on the production of ethanol using established, proven logistics management techniques rather than ethanol sales.


Risks Associated with our Business

        Investing in our company entails a high degree of risk, including those described in the "Risk Factors" section beginning on page 11. You should carefully consider these risks before deciding to invest in our common stock.


Corporate Information

        We are a Delaware corporation organized in February 2003. We and our predecessors have been engaged in the production and marketing of ethanol since 1981. Our corporate offices are located at 120 North Parkway, Pekin, IL 61555-1800. Our website address is http://www.aventinerei.com and our telephone number is 309-347-9200. Information on our website is not incorporated into this prospectus and should not be relied upon in determining whether to make an investment in the common stock.


Recent Developments

        Notes Offering.    On August 19, 2010, we issued and sold $50,000,000 in aggregate principal amount of our 13% Senior Secured Notes due 2015 (the "Notes") in a transaction exempt from the registration requirements under the Securities Act, resulting in gross proceeds to us of approximately $51 million.

        First Amendment to Secured Revolving Credit Facility.    On August 6, 2010, we and our subsidiaries, as borrowers, entered into the First Amendment to Revolving Credit and Security Agreement (the "First Amendment") with the financial institutions party thereto as lenders, and PNC Bank, National Association ("PNC"). The First Amendment amends the March 15, 2010 Revolving Credit and Security Agreement (the "Revolving Credit Agreement") with PNC which provides for a $20.0 million revolving credit facility (our "Revolving Facility") by increasing the letter of credit sublimit under the Revolving Credit Agreement from $12 million to $17 million. The First Amendment also modifies the capital expenditure limitations applicable to us and our subsidiaries under the Revolving Credit Agreement and our daily inventory reporting requirements to permit PNC to agree not to require daily reporting by the borrowers of in-transit inventory.

        Acquisition of Canton, Illinois Facility.    On August 6, 2010, we and New CIE Energy Opco, LLC, d/b/a Riverland Biofuels ("Riverland"), entered into an Asset Purchase Agreement (the "Purchase Agreement") pursuant to which we acquired substantially all of the assets, and assumed specified liabilities, of Riverland for a purchase price of $16.5 million. The assets comprise the Canton facility, and include real property at the plant site as well as surrounding parcels.

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        Debt Commitment Letter.    On August 2, 2010, we entered into a commitment letter (the "Debt Commitment Letter") with Citigroup Global Markets, Inc. ("Citi"), under which Citi has agreed, at a subsequent time, to use its best efforts to arrange a syndicate of lenders that will provide us with a term loan of $175 million (the "New Term Loan Facility"), and to act as lead arranger, bookrunner, administrative agent and collateral agent for the New Term Loan Facility, on the terms and subject to the conditions set forth in the Debt Commitment Letter. Consummation of the debt financing is subject to various conditions set forth in the Debt Commitment Letter, including the absence of certain "material adverse effects" with respect to us and our subsidiaries, taken as a whole. We are under no obligation to enter into any such debt financing and cannot assure you that we will enter into any such financing transaction on terms acceptable to us, if at all.

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The Offering

Common stock offered by selling stockholders

  5,215,523 shares(1)

Use of Proceeds

 

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

Over the Counter Bulletin Board ("OTCBB") symbol

 

AVRW.OB

Dividend policy

 

We do not anticipate that we will pay cash dividends in the near future.

References in this prospectus to the number of shares offered or outstanding do not include (i) 279,550 shares subject to outstanding options and 449,856 shares subject to outstanding warrants at an exercise price of $40.94 per share or (ii) up to 1,220,530 shares that may be issued to the selling stockholders in distributions pursuant to 1145(b) under Chapter 11 of Title 11 of the U.S. Code (the "Bankruptcy Code") pursuant to our plan of reorganization which was confirmed on February 24, 2010 and made effective on March 15, 2010, unless we state otherwise or the context otherwise requires.


(1)
See "Selling Stockholders" for more information on the selling stockholders.

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Summary Historical Consolidated Financial Data

        The following tables set forth summary historical consolidated financial data of Aventine Renewable Energy Holdings, Inc. and its subsidiaries on or as of the dates and for the periods indicated. We have derived the summary historical consolidated financial data as of December 31, 2009, 2008 and 2007 and for the years then ended from the historical audited consolidated financial statements of Aventine Renewable Energy Holdings, Inc. and its subsidiaries prepared in accordance with generally accepted accounting principles in the U.S. ("GAAP"), included elsewhere in this prospectus. We have derived the summary historical consolidated financial data as of December 31, 2006 and 2005 and for the years then ended from the historical audited financial statements of Aventine Renewable Energy Holdings, Inc. and its subsidiaries not included in this prospectus. We derived the unaudited consolidated statement of operations data for the four months ended June 30, 2010, the two months ended February 28, 2010 and for the six months ended June 30, 2009, as well as unaudited consolidated balance sheet data as of June 30, 2010, from our unaudited interim consolidated financial statements included elsewhere in this prospectus. We derived the balance sheet data as of February 28, 2010 and June 30, 2009, from our unaudited interim consolidated financial statements not included in this prospectus. The historical results of Aventine Renewable Energy Holdings, Inc. and its subsidiaries for any prior period are not necessarily indicative of the results to be expected in any future period, and financial results for any interim period are not necessarily indicative of results for a full year.

        In connection with our emergence from reorganization proceedings, we implemented fresh-start accounting in accordance with ASC 852 governing reorganizations. We elected to adopt a convenience date of February 28, 2010 (a month end for our financial reporting purposes) for application of fresh-start accounting. In accordance with the ASC 852 rules governing reorganizations, we recorded largely non-cash reorganization income and expense items directly associated with our reorganization proceedings including professional fees, the revaluation of assets, the effects of our reorganization plan and fresh-start accounting and write-off of debt issuance costs. As a result of the application of fresh-start accounting, our financial statements prior to and including February 28, 2010 represent the operations of our pre-reorganization predecessor company and are presented separately from the financial statements of our post-reorganization successor company. As a result of the application of fresh-start accounting, the financial statements prior to and including February 28, 2010 are not fully comparable with the financial statements for periods on or after February 28, 2010.

        The summary historical consolidated financial information set forth below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Selected Historical Consolidated Financial Data" and the consolidated financial statements and notes thereto included elsewhere in this prospectus.

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  Predecessor  
 
  Successor  
 
   
   
  Year Ended December 31,  
 
  Four months
ended June 30,
2010
  Two months
ended February 28,
2010
  Six months
ended June 30,
2009
 
 
  2009   2008   2007   2006   2005  

Statement of Operations Data:

                                                 

(in thousands, except per share amounts)

                                                 

Net sales

  $ 133,878   $ 77,675   $ 354,657   $ 594,623   $ 2,248,301   $ 1,571,607   $ 1,592,420   $ 935,468  

Cost of goods sold

    (132,766 )   (66,686 )   (375,980 )   (585,904 )   (2,239,340 )   (1,497,807 )   (1,460,806 )   (848,053 )
                                   

Gross profit

    1,112     10,989     (21,323 )   8,719     8,961     73,800     131,614     87,415  

Selling, general and administrative expenses

    (14,286 )   (4,608 )   (16,691 )   (26,694 )   (35,410 )   (36,367 )   (28,328 )   (22,500 )

Demobilization costs associated with expansion projects

                    (9,874 )            

Impairment of plant development costs

                    (1,557 )            

Other income (expense)

    (1,659 )   (515 )   173     (1,510 )   2,936     1,113     3,389     989  
                                   

Operating income (loss)

    (14,833 )   5,866     (37,841 )   (19,485 )   (34,944 )   38,546     106,675     65,904  

Other income (expense):

                                                 

Net income (loss)

  $ (16,359 ) $ (266,293 ) $ (73,502 ) $ (46,260 ) $ (48,326 ) $ 35,137   $ 59,469   $ 34,586  

Net income (loss) attributable to non-controlling interest

                    (1,230 )   1,338     4,568     2,404  
                                   

Net income (loss) attributable to controlling interest

  $ (16,359 ) $ (266,293 ) $ (73,502 ) $ (46,260 ) $ (47,096 ) $ 33,799   $ 54,901   $ 32,182  

Per Share Data:

                                                 

Income (loss) per common share-basic

  $ (1.87 ) $ (6.14 ) $ (1.71 ) $ (1.08 ) $ (1.12 ) $ 0.81   $ 1.43   $ 0.93  

Basic weighted-average common shares

    8,581     43,401     42,968     42,968     42,136     41,886     38,411     34,686  

Income (loss) per common share-diluted

  $ (1.87 ) $ (6.14 ) $ (1.71 ) $ (1.08 ) $ (1.12 ) $ 0.80   $ 1.39   $ 0.89  

Diluted weighted-average common and common equivalent shares

    8,581     43,401     42,968     42,968     42,136     42,351     39,639     36,052  

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  Predecessor  
 
  Successor  
 
   
   
  Year Ended December 31,  
 
  Four months
ended June 30,
2010
  Two months
ended February 28,
2010
  Six months
ended June 30,
2009
 
 
  2009   2008   2007   2006   2005  

Other Data (unaudited):

                                                 

(in thousands, except per bushel and per gallon amounts)

                                                 

EBITDA(1)

  $ (10,897 ) $ (263,164 ) $ (62,254 ) $ (26,164 ) $ (38,009 ) $ 49,708   $ 94,877   $ 67,555  

Adjusted EBITDA(1)

  $ (8,016 ) $ 8,475   $ (17,916 ) $ 8,812   $ 878   $ 56,913   $ 115,953   $ 69,485  

Gallons sold

    64,098     31,478     173,623     277,471     935,986     690,171     695,784     529,836  

Capital expenditures

  $ 21,498   $ 2,086   $ 901   $ 2,279   $ 265,878   $ 235,211   $ 76,499   $ 20,672  

Average price per gallon of ethanol sold

  $ 1.63   $ 1.91   $ 1.69   $ 1.75   $ 2.22   $ 2.08   $ 2.18   $ 1.63  

Average price of corn per bushel

  $ 3.57   $ 3.66   $ 4.17   $ 3.87   $ 5.02   $ 3.76   $ 2.41   $ 2.08  

Balance Sheet Data:

                                                 

(in thousands, at period end)

                                                 

Total assets

  $ 341,815   $ 364,305   $ 699,276   $ 713,675   $ 799,459   $ 762,185   $ 408,136   $ 221,977  

Total debt(2)

  $ 105,000   $ 110,252   $ 42,765   $ 42,765   $ 352,200   $ 300,000       $ 161,514  

Stockholders' equity (deficit)

  $ 203,630   $ 219,923   $ 237,665   $ 267,532   $ 308,796   $ 343,871   $ 304,163   $ (20,654 )

(1)
The following table reconciles net income (loss) to our EBITDA and Adjusted EBITDA for each period presented above. We have included EBITDA and Adjusted EBITDA primarily as performance measures because management uses them as key measures of our performance and ability to generate cash necessary to meet our future requirements for debt service, capital expenditures, working capital and taxes.

 
   
  Predecessor  
 
  Successor  
 
   
   
  Year Ended December 31,  
 
  Four months
ended June 30,
2010
  Two months
ended February 28,
2010
  Six months
ended June 30,
2009
 
 
  2009   2008   2007   2006   2005  

(in thousands)

                                                 

Net income (loss)

  $ (16,359 ) $ (266,293 ) $ (73,502 ) $ (46,260 ) $ (47,096 ) $ 33,799   $ 54,901   $ 32,182  

Interest income

    (15 )       (11 )   (11 )   (3,040 )   (12,432 )   (4,771 )   (2,218 )

Interest expense(a)

    3,100     1,422     11,002     14,697     5,077     16,240     9,348     16,510  

Income tax expense/(benefit)

    (910 )   (626 )   (6,685 )   (8,956 )   (7,472 )   (477 )   31,685     18,807  

Depreciation

    3,287     2,333     6,942     14,366     14,522     12,578     3,714     2,274  
                                   

EBITDA(b)

  $ (10,897 ) $ (263,164 ) $ (62,254 ) $ (26,164 ) $ (38,009 ) $ 49,708   $ 94,877   $ 67,555  
                                   

Loss on early extinguishment of debt

                            14,598      

Loss related to auction rate securities

                    31,601              

Impairment of plant development costs

                    1,557              

Reorganization items

        20,282     42,749     32,440                  

Gain due to plan effects

        (136,574 )                        

Loss due to fresh-start accounting adjustments

        387,655                          

Stock-based compensation

    2,881     276     1,589     2,536     5,729     7,205     6,478     1,930  
                                   

Adjusted EBITDA(c)

  $ (8,016 ) $ 8,475   $ (17,916 ) $ 8,812   $ 878   $ 56,913   $ 115,953   $ 69,485  
                                   

(a)
Contractual interest expense was $4.4 million, $6.4 million, and $36.6 million for the four months ended June 30, 2010, two months ended February 28, 2010, and the year ended December 31, 2009, respectively.

(b)
EBITDA is defined as earnings before interest expense, interest income, income tax expense, and depreciation. EBITDA is not a measure of financial performance under GAAP and should not be considered an alternative to net earnings or any other

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    measure of performance under GAAP or to cash flows from operating, investing or financing activities as an indicator of cash flows or as a measure of liquidity. In particular:

    EBITDA has its limitations as an analytical tool, and you should not consider it in isolation or as a substitute for analysis of our results as reported under generally accepted accounting principles. Some of the limitations of EBITDA are:

    EBITDA does not reflect our cash used for capital expenditures;

    Although depreciation and amortization are non-cash charges, the assets being depreciated or amortized often will have to be replaced and EBITDA does not reflect the cash requirements for such replacements;

    EBITDA does not reflect changes in, or cash requirements for, our working capital requirements;

    EBITDA does not reflect the cash necessary to make payments of interest or principal on our indebtedness; and

    EBITDA includes non-recurring loss items which are reflected in other income (expense).

(c)
In order to emphasize the effects of non-recurring income and loss items in our financial statements, we also report a second computation referred to as Adjusted EBITDA which adjusts EBITDA for those non-recurring items. Adjusted EBITDA here is adjusted for, among other things, stock based compensation and non-recurring restructuring charges. Management believes Adjusted EBITDA is a meaningful measure of liquidity and our ability to service debt because it provides a measure of cash for such purposes. Additionally, management provides an Adjusted EBITDA measure so that investors will have the same financial information that management uses with the belief that it will assist investors in properly assessing our performance on a year-over-year and quarter-over-quarter basis.
(2)
Prior to March 1, 2010, total debt includes amounts outstanding under: 1) our revolving credit agreement; 2) our senior unsecured notes in 2007 and 2008; 3) our debtor-in-possession debt facility; and 4) our previously outstanding senior secured floating rate notes. The senior unsecured notes are reflected in pre-petition liabilities subject to compromise at December 31, 2009. On or after March 1, 2010, total debt includes amounts outstanding under: 1) our Revolving Facility; 2) our Notes; and 3) our short-term note payable to Kiewit Energy Company.

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RISK FACTORS

Risks Relating to Our Business

Since our consolidated financial statements reflect fresh-start accounting adjustments, our future financial statements will not be comparable in many respects to our financial information from prior periods.

        On April 7, 2009, we filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. Our plan of reorganization became effective on March 15, 2010. In connection with our emergence from the Chapter 11 reorganization proceedings, we implemented fresh-start accounting in accordance with ASC 852 as of February 28, 2010, which had a material effect on our consolidated financial statements. Thus, our future consolidated financial statements will not be comparable in many respects to our consolidated financial statements for periods prior to our adoption of fresh-start accounting and prior to accounting for the effects of the reorganization proceedings. Our past financial difficulties and bankruptcy filing may have harmed, and may continue to have a negative effect on, our relationships with investors, customers and suppliers.

We have substantial liquidity needs and may be required to seek additional financing.

        Our principal sources of liquidity are cash and cash equivalents on hand, cash provided by operations, and cash provided by our Revolving Facility. Our liquidity position is significantly influenced by our operating results, which in turn are substantially dependent on commodity prices, especially prices for corn, ethanol, natural gas and unleaded gasoline. As a result, adverse commodity price movements adversely impact our liquidity. We cannot assure you that the amounts of cash available from operations, together with our Revolving Facility, will be sufficient to fund our operations. Furthermore, the construction of our Aurora and Mount Vernon plants is expected to cost approximately $80.0 million.

        Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. Accordingly, there can be no assurance as to the success of our efforts. In the event that cash flows and borrowings under our Revolving Facility are not sufficient to meet our cash requirements, we may be required to seek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms.

We may be unable to secure additional financing.

        Our ability to arrange, in addition to our Revolving Facility, financing (including any extension or refinancing) and the cost of additional financing are dependent upon numerous factors. Access to capital (including any extension or refinancing) for participants in the biofuels industry, including us, has been significantly restricted and may, as a result of our voluntary petition for relief under Chapter 11 of the Bankruptcy Code in April 2009 and recent emergence from the reorganization proceedings on March 15, 2010, be further restricted in the future. Other factors affecting our access to financing include:

    general economic and capital market conditions;

    conditions in biofuels markets;

    regulatory developments;

    credit availability from banks or other lenders for us and our industry peers, as well as the economy in general;

    investor confidence in the biofuels industry and in us;

    the continued reliable operation of our ethanol production facilities; and

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    provisions of tax and securities laws that are conducive to raising capital.

We may not be able to generate enough cash flow to meet our debt obligations.

        We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments, including our Notes. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including our Notes. Many of these factors, such as ethanol prices, corn prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

        If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

    refinancing or restructuring our debt:

    selling assets;

    reducing or delaying capital investments; or

    seeking to raise additional capital.

        We cannot assure you, however, that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including, but not limited to, our obligations under our Notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

We have significant indebtedness under the Notes and our Revolving Facility. The Notes and our Revolving Facility have substantial restrictions and affirmative covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations.

        As of June 30, 2010, after giving effect to the offer and sale of an additional $50 million in principal amount of Notes in August 2010, we had an aggregate of approximately $155 million in debt outstanding under our Notes. In addition, we had availability under our Revolving Facility of approximately $5.9 million as of June 30, 2010. As a result of our indebtedness, we will use a portion of our cash flow to pay interest and principal when due, which will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate.

        Our indebtedness under the Notes and our Revolving Facility restricts our ability to engage in certain activities. These restrictions limit our ability, subject to certain exceptions, to, among other things:

    incur additional indebtedness and issue stock;

    make prepayments on or purchase indebtedness in whole or in part;

    pay dividends and other distributions with respect to our capital stock or repurchase our capital stock or make other restricted payments;

    make investments;

    enter into transactions with affiliates;

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    create or incur liens to secure debt;

    consolidate or merge with another entity, or allow one of our subsidiaries to do so;

    lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;

    incur dividend or other payment restrictions affecting subsidiaries;

    make capital expenditures beyond specified limits;

    engage in specified business activities; and

    acquire facilities or other businesses.

        We also are required to comply with certain affirmative covenants. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants could result in an event of default, which, if it continues beyond any applicable cure periods, could cause all of our existing indebtedness to be immediately due and payable.

        We depend on our Revolving Facility for future working capital needs. If there is an event of default by us under our Revolving Facility that continues beyond any applicable cure period, we may be unable to borrow to fund our operations.

We operate in a highly competitive industry with low barriers to entry.

        In the U.S., we compete with other corn processors and refiners, including Archer-Daniels-Midland Company, Green Plains Renewable Energy, Valero, Biofuels Energy Corporation, Hawkeye Holdings, Inc., Pacific Ethanol, Cargill, Inc. and A.E. Staley Manufacturing Company, a subsidiary of Tate & Lyle, PLC. Some of our competitors are divisions of larger enterprises and have greater financial resources than we do. Although many of our competitors are larger than we are, we also have smaller competitors. Farm cooperatives comprised of groups of individual farmers have been able to compete successfully. As of December 2009, the top ten domestic producers accounted for approximately 47.9% of all production. If our competitors consolidate or otherwise grow and/or we are unable to similarly increase our size and scope, our business and prospects may be significantly and adversely affected.

        We also face increasing competition from international suppliers. Although there is a tariff on foreign produced ethanol that is slightly larger than the federal ethanol tax incentive, ethanol imports equivalent to up to 7% of total domestic production from certain countries were exempted from this tariff under the Caribbean Basin Initiative ("CBI") to spur economic development in Central America and the Caribbean.

        Our competitors also include plants owned by farmers who earn their livelihood through the sale of corn, and hence may not be as focused on obtaining optimal value for their produced ethanol as we are.

Our business is dependent upon the availability and price of corn. Significant disruptions in the supply of corn will materially affect our operating results. In addition, since we generally cannot pass on increases in corn prices to our customers, continued periods of historically high corn prices will also materially adversely affect our operating results.

        The principal raw material we use to produce ethanol and ethanol by-products is corn. In 2009, we purchased approximately 74.2 million bushels of corn at a cost of $287.1 million, which comprised about 72% of our total cost of production. In 2009, our average corn cost ranged from a low of $3.31 per bushel in September 2009 to a high of $4.48 per bushel in January 2009. Corn prices began to rise

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significantly beginning in September 2006. We believe a systemic shift has occurred in the marketplace for corn, and the price of corn will remain significantly higher than the historical averages. The increase in U.S. ethanol capacity under construction could outpace increases in corn production, which may further increase corn prices and impact our profitability.

        Changes in the price of corn have had an impact on our business. In general, higher corn prices produce lower profit margins and, therefore, represent unfavorable market conditions. This is especially true when market conditions do not allow us to pass along increased corn costs to our customers. At certain levels, corn prices may make ethanol uneconomical to use in markets and volumes above the requirements set forth in the renewable fuels standard ("RFS") or for which ethanol is used as an oxygenate in order to meet federal and state fuel emission standards.

        The price of corn is influenced by general economic, market and regulatory factors. These factors include weather conditions, farmer planting decisions, government policies and subsidies with respect to agriculture and international trade and global demand and supply. The significance and relative impact of these factors on the price of corn is difficult to predict. Factors such as severe weather or crop disease could have an adverse impact on our business because we may be unable to pass on higher corn costs to our customers. Any event that tends to negatively impact the supply of corn will tend to increase prices and potentially harm our business. The increasing ethanol capacity could boost demand for corn and result in increased prices for corn. We expect the price of corn to continue to remain at levels that would be considered as high when compared to historical periods.

        In an attempt to partially offset the effects of fluctuations in corn costs on operating income, we have taken hedging positions in the corn futures markets in the past. However, these hedging transactions also involve risk to our business. See "We may engage in hedging or derivative transactions which involve risks that can harm our business."

The use and demand for ethanol and its supply are highly dependent on various federal and state legislation and regulation, and any changes in legislation or regulation could cause the demand for ethanol to decline or its supply to increase, which could have a material adverse effect on our business, results of operations and financial condition.

        Various federal and state laws, regulations and programs have led to increased use of ethanol in fuel. For example, certain laws, regulations and programs provide economic incentives to ethanol producers and users. Among these regulations are (1) the RFS, which requires an increasing amount of renewable fuels to be used in the U.S. each year, (2) the VEETC, which provides a tax credit of $0.45 per gallon on 10% ethanol blends that is set to expire in 2010 (legislation has been introduced in Congress to extend the VEETC at a reduced level, and action is expected on the proposal prior to the November mid-term elections; however, the final outcome remains unclear), (3) the small ethanol producer tax credit, for which we do not qualify because of the size of our ethanol plants, and (4) the federal "farm bill," which establishes federal subsidies for agricultural commodities including corn, our primary feedstock. These laws, regulations and programs are regularly changing, and sections of the RFS currently are the subject of legal challenges in federal court. Federal and state legislators and environmental regulators could adopt or modify laws, regulations or programs that could affect adversely the use of ethanol. Barring a change in current regulation, requirements for the state of California will make it difficult for ethanol produced from corn in many Midwestern states to be used as a fuel in California beginning in 2011. In addition, certain state legislatures oppose the use of ethanol because they must ship ethanol in from other corn-producing states, which could significantly increase gasoline prices in the state.

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The Renewable Fuel Standard 2 recently released by the Environmental Protection Agency ("EPA") may require producers to include alternative technologies in plants under construction, which may increase the cost to complete our facilities.

        The EPA's recently released Renewable Fuel Standard 2 includes requirements that the lifecycle greenhouse gas emissions of a qualifying renewable fuel must be less than the lifecycle greenhouse gas emissions of the 2005 baseline average gasoline or diesel fuel that it replaces. The lifecycle greenhouse gas emissions threshold for renewable fuel (e.g., ethanol) is 20%. Fuels from existing capacity of current facilities and from facilities that commenced construction prior to December 19, 2007 are exempt or grandfathered from the 20% lifecycle requirement under certain circumstances. Plants whose construction commenced prior to December 19, 2007 must be completed within three years in order to be exempt or grandfathered from the 20% lifecycle requirement. The EPA recently issued a Direct Final Rule that would, among other things, require all plants that commence construction prior to the enactment of the EISA to complete construction by December 19, 2010. Plants not exempt or grandfathered must include advanced efficient technologies as defined by the regulations in order to meet the Renewable Fuel Standard 2 requirements. If our Mt. Vernon plant and the Aurora West plant are not completed within the required three years, the plants may not be exempt or grandfathered from the 20% lifecycle requirement and could require additional advanced efficient technologies to be included in the construction, which is likely to require additional capital which may be substantial.

If the expected increase in ethanol demand does not occur, or if the demand for ethanol otherwise decreases, the excess capacity in our industry may increase further.

        Domestic ethanol capacity has increased significantly from 1.3 billion gallons per year in 1997 to 12.5 billion gallons per year at the end of 2008. According to the RFA, as of January 25, 2010, approximately 1.4 billion gallons per year of production capacity is currently under construction. Through November 2009, U.S. ethanol demand exceeded U.S. ethanol production by 139 million gallons. Demand for ethanol increased by 12% over 2008 through increased penetration into new markets and a government mandate, but the production capacity of U.S. ethanol producers continues to exceed demand. At the end of 2009, there was approximately 1.2 billion gallons of production capacity shut-in. If additional demand for ethanol is not created, either through discretionary blending or an increase in the blending percentage allowed by the EPA, the excess supply may cause additional plants to shutter production or cause ethanol prices to decrease further, perhaps substantially.

Growth in the sale and distribution of ethanol is dependent on the changes in and expansion of related infrastructure, which may not occur on a timely basis, if at all, and our operations could be adversely affected by infrastructure disruptions.

        Substantial development of infrastructure by persons and entities outside our control are required for our operations and the ethanol industry generally to grow. Areas requiring expansion include, but are not limited to, additional rail capacity, additional storage facilities for ethanol, increases in truck fleets capable of transporting ethanol within localized markets, expansion of refining and blending facilities to handle ethanol, growth in service stations equipped to handle ethanol fuels, and growth in the fleet of flexible fuel vehicles capable of using E85 fuel. Substantial investments required for these infrastructure changes and expansions may not be made or they may not be made on a timely basis. Any delay or failure in making the changes in or expansion of infrastructure could hurt the demand or prices for our products, impede our delivery of products, impose additional costs on us or otherwise have a material adverse effect on our business, results of operations or financial condition. Our business is dependent on the continuing availability of infrastructure and any infrastructure disruptions could have a material adverse effect on our business, results of operations and financial condition.

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The market for natural gas is subject to market conditions that create uncertainty in the price and availability of the natural gas that we utilize in our manufacturing process.

        We rely upon third parties for our supply of natural gas which is consumed in the production of ethanol at our Illinois dry mill facility and our Nebraska facility. The prices for and availability of natural gas are subject to volatile market conditions. These market conditions often are affected by factors beyond our control such as weather conditions, overall economic conditions and foreign and domestic governmental regulation and relations. Significant disruptions in the supply of natural gas could temporarily impair our ability to produce ethanol for our customers. Further, increases in natural gas prices or changes in our natural gas costs relative to natural gas costs paid by competitors may adversely affect our results of operations and financial condition. The price fluctuation in natural gas prices over the ten year period from 2000 through December 31, 2009, based on the New York Mercantile Exchange, or NYMEX, daily futures data, has ranged from a low of $1.83 per MMBtu in September 2001 to a high of $15.38 per MMBtu in December 2005. We currently use approximately 3.4 million MMBtu's of natural gas annually, depending upon business conditions, in the manufacture of our products. Our usage of natural gas will increase with the planned expansion of our production facilities.

        In an attempt to minimize the effects of fluctuations in natural gas costs on operating income, we have taken hedging positions in the natural gas forward or futures markets in the past; however, these hedging transactions also involve risk to our operations. Since natural gas prices are volatile and we are not currently taking hedging positions, our results could be adversely affected by an increase in natural gas prices. See "—We may engage in hedging or derivative transactions which involve risks that can harm our business."

Fluctuations in the demand for gasoline may reduce demand for ethanol.

        Ethanol is marketed as an oxygenate to reduce vehicle emissions from gasoline, as an octane enhancer to improve the octane rating of gasoline with which it is blended and as a fuel extender. As a result, ethanol demand has historically been influenced by the supply of and demand for gasoline. If gasoline demand decreases, our ability to sell our product and our results of operations and financial condition may be materially adversely affected.

Changes in ethanol prices can affect the value of our inventory which may significantly affect our profitability.

        Our inventory is valued based upon a weighted average of our cost to produce ethanol and the price we pay for ethanol that we purchase from other producers. Due to the dissolution of the marketing alliance in early 2009, we no longer make purchases of ethanol from alliance partners but continue to engage in purchase/resale transactions, as needed, to fulfill our sales commitments. Changes, either upward or downward, in our purchased cost of ethanol or our own production costs, will cause the inventory value to fluctuate from period to period, perhaps significantly. These changes in value flow through our statement of operations as the inventory is sold and can significantly increase or decrease our profitability.

The relationship between the sales price of our co-products and the price we pay for corn can fluctuate significantly which may affect our results of operations and profitability.

        We sell co-products and bio-products that are remnants of the ethanol production process in order to reduce our corn costs and increase profitability. Historically, sales prices for these co-products have tracked along with the price of corn. However, there have been occasions when the value of these co-products and bio-products has lagged behind increases in corn prices. As a result, we may occasionally generate less revenue from the sale of these co-products and bio-products relative to the price of corn. In addition, several of our co-products compete with similar products made from other

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plant feedstock. The cost of these other feedstocks may not have risen as corn prices have risen. Consequently, the price we may receive for these products may not rise as corn prices rise, thereby lowering our cost recovery percentage relative to corn.

Fixed price and gasoline related contracts for ethanol may be at a price level lower than the prevailing price.

        At any given time, contract prices for ethanol may be at a price level different from the current prevailing price, and such a difference could materially adversely affect our results of operations and financial condition. As of June 30, 2010 and December 31, 2009, we had no fixed price or gasoline related sales contracts for ethanol.

Our results of operations may be adversely affected by technological advances.

        The development and implementation of new technologies may result in a significant reduction in the costs of ethanol production. We cannot predict when new technologies may become available, the rate of acceptance of new technologies by our competitors or the costs associated with such new technologies. In addition, advances in the development of alternatives to ethanol, or corn ethanol in particular, could significantly reduce demand for or eliminate the need for ethanol, or corn ethanol in particular, as a fuel oxygenate or octane enhancer.

        Any advances in technology which require significant capital expenditures for us to remain competitive or which otherwise reduce demand for ethanol will have a material adverse effect on our results of operations and financial condition.

We are substantially dependent on our three operational facilities and any operational disruption could result in a reduction of our sales volumes and could cause us to incur substantial expenditures.

        The substantial majority of our net income is derived from the sale of ethanol and the related bio-products and co-products that we produce at our Illinois facilities and our Nebraska facility. Our operations may be subject to significant interruption if either of the Illinois facilities or Nebraska facility experiences a major accident or is damaged by severe weather or other natural disaster. In addition, our operations may be subject to labor disruptions and unscheduled downtime, or other hazards inherent in our industry. Some of those hazards may cause personal injury and loss of life, severe damage to or destruction of property, natural resources and equipment, pollution and environmental damage, clean-up responsibilities, and repairs to resume operations and may result in suspension or termination of operations and the imposition of civil or criminal penalties. As protection against these hazards, we maintain property, business interruption and casualty insurance which we believe is in accordance with customary industry practices, but we cannot provide any assurance that this insurance will be adequate to fully cover the potential hazards described above or that we will be able to renew this insurance on commercially reasonable terms or at all.

Risks associated with the operation of our production facilities may have a material adverse effect on our business.

        Our revenue is dependent on the continued operation of our various production facilities. The operation of production plants involves many risks including:

    the breakdown, failure or substandard performance of equipment or processes;

    inclement weather and natural disasters;

    the need to comply with directives of, and obtain and maintain all necessary permits from, governmental agencies;

    raw material supply disruptions;

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    labor force shortages, work stoppages, or other labor difficulties; and

    transportation disruptions.

        The occurrence of material operational problems, including but not limited to the above events, may have an adverse effect on the productivity and profitability of a particular facility, or to us as a whole.

We may encounter unanticipated difficulties in operating our plants under construction, which could reduce sales and cause us to incur substantial losses.

        The Delta-T technology to be utilized at our plants under construction is currently in use only in a small number of ethanol plants, mostly with smaller capacities than ours. We are aware of certain plant design issues that may impede the reliable operation of the plants and continuous operations. We are in the process of addressing these issues but we have no assurance that our initiatives will be successful or can be implemented in a timely fashion or without an extended period of interruption to operations.

We are contractually obligated to complete certain capacity expansions in Aurora, Nebraska and Mount Vernon, Indiana. If we fail to complete them in a timely manner, we may be subject to material penalties.

        On or about March 23, 2010, in accordance with the terms of a stipulation filed with the U.S. Bankruptcy Court for the District of Delaware (the "Bankruptcy Court"), we paid approximately $2.1 million to the Aurora Co-operative, representing penalties of (i) approximately $0.8 million, arising under a Master Development Agreement with the Aurora Co-operative for failure to complete construction of the Aurora West facility, for the period of July 1, 2009 through and including December 31, 2009, and (ii) approximately $1.3 million in the event that we do not complete the Aurora West facility by September 30, 2010 for each month starting from January 1, 2010 through and including September 30, 2010. If the plant is not operational by October 1, 2010, we will be subjected to additional penalties of $138,889 per month from October 1, 2010 through and including when the plant is operational, but not to exceed total penalties of $5.0 million. In addition, if we fail to diligently pursue construction of the Aurora West plant or complete the plant by July 31, 2012, the Aurora Co-operative has the option to repurchase the property at $16,500.00 per acre (subject to adjustment). Pursuant to the plan of reorganization, various other agreements with the Aurora Co-operative, as amended, were assumed by us and should ensure that the Aurora West facility will be able to operate once completed. However, there is no certainty that future disagreements between us and the Aurora Co-operative will not arise as to the terms of these agreements, which could impact completion of the Aurora West facility.

        Prior to confirmation of the plan of reorganization, we amended our lease with the Indiana Ports Commission to provide additional flexibility as to the timing of the completion of Phase One and the construction of the Phase Two expansion at the Mt. Vernon facility. This lease, as amended, requires our Mt. Vernon subsidiary to substantially complete Phase One (an initial 110 million gallons of capacity) by December 31, 2010 and to construct Phase Two (an additional 110 million gallons of capacity) before constructing a new facility elsewhere (other than at Aurora West). If we are in default of these obligations, the Indiana Ports Commission may, subject to specified cure rights, take over construction and complete the facility at our expense (among other remedies).

We depend on rail, truck and barge transportation for delivery of corn to us and the distribution of ethanol to our customers.

        We depend on rail, truck and barge transportation to deliver corn to us and to distribute ethanol to the terminals currently in our network. Ethanol is not currently distributed by pipeline. Disruption to the timely supply of these transportation services or increases in the cost of these services for any reason, including the availability or cost of fuel or railcars to serve our facilities under construction,

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regulations affecting the industry, or labor stoppages in the transportation industry, could have an adverse effect on our ability to supply corn to our production facilities or to distribute ethanol to our terminals, and could have a material adverse effect on our financial performance.

Our floating rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

        Borrowings under our Revolving Facility bear interest at floating rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Consumer resistance to the use of ethanol may affect the demand for ethanol, which could affect our ability to market our product.

        Media reports in the mainstream press indicate that some consumers believe the use of ethanol will have a negative impact on retail gasoline prices or is the reason for increases in food prices. Many also believe that ethanol adds to air pollution and harms car and truck engines. Still other consumers believe that the process of producing ethanol actually uses more fossil energy, such as oil and natural gas, than the amount of energy produced by ethanol. These consumer beliefs could be wide-spread in the future. If consumers choose not to buy ethanol blended fuels, it would affect the demand for the ethanol we produce which could lower demand for our product and negatively affect our profitability.

Various studies have criticized the efficiency of ethanol, which could lead to the reduction or repeal of incentives and tariffs that promote the use and domestic production of ethanol.

        Although many trade groups, academics and governmental agencies have supported ethanol as a fuel additive that promotes a cleaner environment, others have criticized ethanol production as consuming considerably more energy and emitting more greenhouse gases than other biofuels. In particular, two February 2008 studies concluded the current production of corn-based ethanol results in more greenhouse gas emissions than conventional fuels if both direct and indirect greenhouse gas emissions, including those resulting from land use changes resulting from planting crops for ethanol feedstocks, are taken into account. Other studies have suggested that corn-based ethanol is less efficient than ethanol produced from switch grass or wheat grain. If these views gain acceptance, support for existing measures promoting use and domestic production of corn-based ethanol could decline, leading to reduction or repeal of these measures.

We sell ethanol primarily to the major oil companies and traders and therefore we can from time to time be subject to a high degree of concentration of our sales and accounts receivable.

        We sell ethanol to most of the major integrated oil companies and a significant number of large, independent refiners and petroleum wholesalers. Our trade receivables result primarily from our ethanol marketing operations. As a general policy, collateral is not required for receivables, but customers' financial condition and creditworthiness are evaluated regularly. Credit risk concentration related to our accounts receivable results from our top ten customers having generated 54.7% and 47% of our consolidated net sales for the years ended December 31, 2009 and 2008, respectively.

        For the 2009 fiscal year, Biourja Trading accounted for 10.5% and Exxon Mobil accounted for 11.1% of our consolidated net sales volume. No other customers in fiscal 2009 represented more than 10% of our consolidated net sales volume. No customers in 2008 or 2007 represented more than 10% of our consolidated net sales volume.

        If we would suddenly lose a major customer and not be able to replace the demand for our product very quickly, it could have a material impact on our sales and profitability.

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Research is currently underway to develop production of biobutanol, a product that could directly compete with ethanol and may have potential advantages over ethanol.

        Biobutanol, an advanced biofuel produced from agricultural feedstock, is currently being developed by various parties, including a partnership between BP and DuPont. According to the partnership, biobutanol has many advantages over ethanol. The advantages include: low vapor pressure, making it more easily added to gasoline; energy content closer to that of gasoline, such that the decrease in fuel economy caused by the blending of biobutanol with gasoline is less than that of other biofuels when blended with gasoline; it can be blended at higher concentrations than other biofuels for use in standard vehicles; it is less susceptible to separation when water is present than in pure ethanol-gasoline blends; and it is expected to be potentially suitable for transportation in gas pipelines, resulting in a possible cost advantage over ethanol producers relying on rail transportation. Although BP and DuPont have not announced a timeline for producing biobutanol on a large scale, if biobutanol production comes online in the U.S., biobutanol could have a competitive advantage over ethanol and could make it more difficult to market our ethanol, which could reduce our ability to generate revenue and profits.

We, and some of our major customers, have unionized employees and could be adversely affected by labor disputes.

        Some of our employees and some employees of our major customers are unionized. At December 31, 2009, approximately 55% of our employees were unionized. Our unionized employees are hourly workers located at our Illinois facilities. The unionized employees are covered by a collective bargaining agreement between our subsidiary, Aventine Renewable Energy, Inc. and the United Steelworkers International Union, Local 7-662, or the Union.

        The collective bargaining agreement with the Union was scheduled to expire in October 2009. Prior to the expiration of the collective bargaining agreement, we and the Union agreed to extend the term of the current collective bargaining agreement by one year through and including October 31, 2010 on the same terms and conditions. The collective bargaining agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse affect on our business, financial condition and results of operations. There is no certainty that the current collective bargaining agreement will be further extended or that a new collective bargaining agreement will be reached.

If we are unable to attract and retain key personnel, our ability to operate effectively may be impaired.

        Our ability to operate our business and implement strategies depends, in part, on the efforts of our executive officers and other key employees. Our management philosophy of cost-control means that we operate with a limited number of corporate personnel, and our commitment to a less centralized organization also places greater emphasis on the strength of local management. Our future success will depend on, among other factors, our ability to attract and retain qualified personnel, particularly executive management. The loss of the services of any of our key employees or the failure to attract or retain other qualified personnel, domestically or abroad, could have a material adverse effect on our business or business prospects.

If the amount of non-corn based ethanol, cellulosic biofuels or bio-mass based diesel cannot be increased, our business, results of operations and financial condition will be adversely affected.

        The EISA established a revised RFS for the years 2006 through 2022. The RFS sets forth the minimum amount of renewable fuels that must be present in U.S. transportation fuels. The law starts at 9 billion gallons in 2008 and rises to 36 billion gallons by 2022. For 2015 and all subsequent years, the amount of the renewable fuels mandate that can be satisfied by corn-based ethanol is currently capped at 15 billion gallons. The remainder of the mandate is required to be obtained from cellulosic biofuel

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and other advanced biofuels. Waiver provisions enable the EPA to reduce the renewable fuel volumetric obligation targets for reasons such as severe economic or environmental harm or an inadequate domestic supply of renewable fuels. If our and our competitors' facilities cannot accept feedstocks, other than corn, or if we do not begin producing non-corn based ethanol in the future, our business, results of operations and financial condition may be adversely affected.

Certain countries can import ethanol into the U.S. duty free, which may undermine the ethanol industry in the U.S.

        Imported ethanol is generally subject to a $0.54 per gallon tariff and a 2.5% ad valorem tax that was designed to offset the $0.45 per gallon ethanol subsidy currently available under the federal excise tax incentive program for refineries and blenders that mix ethanol with their gasoline. Legislation has been introduced to extend this tariff, although the final outcome remains unclear. At a certain price level, imported ethanol may become profitable for sale in the U.S. despite the tariff. This occurred in 2006, due to a spike in the ethanol prices and insufficient supply. As a result, there may effectively be a ceiling on U.S. ethanol prices. This, combined with uncertainties surrounding U.S. producers' ability to meet domestic demand, resulted in significant imports of ethanol, especially from Brazil. Furthermore, East Coast facilities are better suited to bringing in product by water rather than rail (the preferred path for ethanol from the Midwest). The combination made it more economic for some buyers to import ethanol with the full import duty than to bring supplies from the Midwest. Given the increase in ethanol demand as a result of the new RFS and potential transportation bottlenecks delivering material from the Midwest, imports of ethanol could rise.

        There is a special exemption from the tariff for ethanol imported from 24 countries in Central America and the Caribbean islands which is limited to a total of 7% of U.S. production per year (with additional exemptions for ethanol produced from feedstock in the Caribbean region over the 7% limit). In addition the NAFTA (The North America Free Trade Agreement which was signed into law January 1, 1994) countries—Canada and Mexico—are exempt from duty. See "Business—Legislative Drivers and Governmental Regulations—The federal ethanol tax incentive program." Imports from the exempted countries have increased in recent years and are expected to increase further as a result of new plants under development.

We may be adversely affected by environmental, health and safety laws, regulations and liabilities.

        We are subject to extensive federal, state and local environmental, health and safety laws, regulations and permit conditions (and interpretations thereof), including, among other things, those relating to the discharge of hazardous and other waste materials into the air, water and ground, the generation, storage, handling, use, transportation and/or disposal of hazardous materials, and the health and safety of our employees. Compliance with these laws, regulations, and permits require us to incur significant capital and other costs, including costs to obtain and maintain expensive pollution control equipment. They may also require us to make operational changes to limit actual or potential impacts to the environment. A violation of these laws, regulations or permit conditions can result in substantial administrative and civil fines and penalties, criminal sanctions, imposition of clean-up and site restoration costs and liens, suspension or revocation of necessary permits, licenses and authorizations and/or the issuance of orders enjoining or limiting our current or future operations. In addition, environmental laws and regulations (and interpretations thereof) change over time, and any such changes, more vigorous enforcement policies or the discovery of currently unknown conditions may require substantial additional environmental expenditures.

        We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged for the disposal of hazardous wastes. For instance, over ten years ago soil and groundwater contamination from fuel oil contamination at a storage site was identified at our Illinois campus. The

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fuel oil tanks were removed and a portion of the area has been capped, but no remediation has been performed. If any of these sites are subject to investigation and/or remediation requirements, we may incur strict and/or joint and several liability under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws which impose strict liability for all or part of the costs of such investigation, remediation, or removal costs and for damages to natural resources whether the contamination resulted from the conduct of other or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties or other impacts of our operations. We have not accrued any amounts for environmental matters as of June 30, 2010. The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

        In addition, the hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, abnormal pressures and spills) may result in releases of hazardous substances and other waste materials, and may result in claims from governmental authorities or third parties relating to actual or alleged personal injury, property damage, or damages to natural resources. We maintain insurance coverage against some, but not all, potential losses associated with our operations. Our coverage includes, but is not limited to, physical damage to assets, employer's liability, comprehensive general liability, automobile liability and workers' compensation. We do not carry environmental insurance. We believe that our insurance is adequate for our industry, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of events which result in significant personal injury or damage to our property, natural resources or third parties that is not covered by insurance could have a material adverse impact on our results of operations and financial condition.

        Our air emissions are subject to the federal Clean Air Act, as amended, and similar state laws which generally require us to obtain and maintain air emission permits for our ongoing operations, as well as pre-approval for any expansion or construction of existing facilities or new facilities or modification of certain projects or facilities. Obtaining and maintaining those permits requires us to incur costs, and any future more stringent standards may result in increased costs and may limit or interfere with our operations. In addition, the permits ultimately issued may impose conditions which are more costly to implement than we had anticipated. These costs could have a material adverse effect on our financial condition and results of operations, and could adversely affect us in our efforts to compete with foreign producers not subject to such stringent requirements. Our failure to comply with air emissions laws and regulations could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.

        Federal and state environmental authorities have been investigating alleged excess volatile organic compounds ("VOCS") emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities. The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility. If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar matter at our Nebraska facility due to the larger size of the Illinois wet mill facility. As of yet we have not established reserves for possible costs we may incur in connection with this investigation. In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.

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        We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the EPA National Emission Standards for Hazardous Air Pollutants ("NESHAP") for industrial, commercial and institutional boilers and process heaters. This NESHAP was issued in 2004 but subsequently vacated in 2007. The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers. The EPA is currently rewriting the NESHAP, which is expected to be more stringent than the vacated version. In the absence of a final NESHAP for industrial, commercial and institutional boilers and process heaters, we are working with state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed. We currently cannot estimate the amount that will be needed to comply with any future federal or state technology requirement regarding air emissions from our boilers.

        We currently generate revenue from the sale of carbon dioxide, a greenhouse gas, which is a co-product of the ethanol production process at each of our Illinois and Nebraska facilities. National greenhouse gas legislation is in the early stages of development in the U.S., and we are currently unable to determine the impact of potential greenhouse gas reduction requirements. Mandatory greenhouse gas emissions reductions may impose increased costs on our business and could adversely impact our operations, including our ability to continue generating revenue from carbon dioxide sales.

We may engage in hedging or derivative transactions which involve risks that can harm our business.

        In an attempt to minimize the effects of the volatility of the price of corn, natural gas, electricity and ethanol ("commodities"), we may take economic hedging positions in the commodities. Economic hedging arrangements also expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or there is a change in the expected differential between the underlying price in the hedging agreement and the actual price of the commodities. Although we attempt to link our economic hedging activities to sales plans and pricing activities, occasionally such hedging activities can themselves result in losses. We have not been significantly involved in these activities since February 2009. As a result, our results of operations may be adversely affected during periods in which corn and/or natural gas prices increase.

If our internal computer network and applications suffer disruptions or fail to operate as designed, our operations will be disrupted and our business may be harmed.

        We rely on network infrastructure and enterprise applications, and internal technology systems for our operational, marketing support and sales, and product development activities. The hardware and software systems related to such activities are subject to damage from earthquakes, floods, lightning, tornadoes, fire, power loss, telecommunication failures and other similar events. They are also subject to acts such as computer viruses, physical or electronic vandalism or other similar disruptions that could cause system interruptions and loss of critical data, and could prevent us from fulfilling our customers' orders. We have developed disaster recovery plans and backup systems to reduce the potentially adverse effects of such events, but there are no assurances such plans and systems would be sufficient. Any event that causes failures or interruption in our hardware or software systems could result in disruption of our business operations, have a negative impact on our operating results, and damage our reputation.

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Risks Relating to this Offering

The trading price for the shares of our common stock may be volatile.

        The liquidity of any market for the shares of our common stock will depend on a number of factors, including:

    the number of stockholders;

    our operating performance and financial condition;

    the market for similar securities; and

    the interest of securities dealers in making a market in the shares of our common stock.

        Historically, the market for common stock has been subject to disruptions that have caused substantial volatility in the prices of these securities, which may not have corresponded to the business or financial success of the particular company. We cannot assure you that the market for the shares of our common stock will be free from similar disruptions. Any such disruptions could have an adverse effect on stockholders. In addition, the price of the shares of our common stock could decline significantly if our future operating results fail to meet or exceed the expectations of market analysts and investors.

        Some specific factors that may have a significant effect on the market price of the shares of our common stock include:

    actual or expected fluctuations in our operating results;

    actual or expected changes in our growth rates or our competitors' growth rates;

    conditions in our industry generally;

    conditions in the financial markets in general or changes in general economic conditions;

    our inability to raise additional capital;

    changes in market prices for our product or for our raw materials; and

    changes in stock market analyst recommendations regarding the shares of our common stock, other comparable companies or our industry generally.

We have no plans to pay regular dividends on our common stock, so you may not receive funds without selling your common stock.

        Our Board of Directors presently intends to retain all of our earnings for the expansion of our business; therefore, we have no plans to pay regular dividends on our common stock. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends, and other considerations that our Board of Directors deems relevant. Also, the provisions of our Revolving Facility restrict the payment of dividends. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment.

Shares eligible for sale could adversely affect the price of the shares of our common stock.

        The market price of the shares of our common stock could decline as a result of sales by our existing stockholders or the perception that such sales might occur. These sales also might make it difficult for our equity securities to be sold in the future at a time and price that we deem appropriate. Substantially all of our outstanding shares are freely tradable or held by holders that have the right to

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require us to register the resale of their shares. If any of our existing stockholders sell a significant number of shares, the market price of our common stock could be adversely affected.

Provisions of our third amended and restated certificate of incorporation and amended and restated bylaws could delay or prevent a takeover of us by a third party.

        Provisions in our third amended and restated certificate of incorporation and amended and restated bylaws and of Delaware corporate law may make it difficult and expensive for a third party to pursue a tender offer, change in control or takeover attempt that is opposed by our management and Board of Directors. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change our management and Board of Directors. See "Description of Capital Stock."

We have "blank check" preferred stock.

        Our third amended and restated certificate of incorporation authorizes the Board of Directors to issue preferred stock without further stockholder action in one or more series and to designate the dividend rate, voting rights and other rights preferences and restrictions. The issuance of preferred stock could have an adverse impact on holders of common stock. Preferred stock is senior to common stock. Additionally, preferred stock could be issued with dividend rights senior to the rights of holders of common stock. Finally, preferred stock could be issued as part of a "poison pill," which could have the effect of deterring offers to acquire our company. See "Description of Capital Stock—Preferred Stock."

The holders of our common stock do not have cumulative voting rights, preemptive rights or rights to convert their common stock to other securities.

        We are authorized to issue 15,000,000 shares of common stock, $0.001 par value per share. As of September 7, 2010, there were 7,364,573 shares of common stock issued and outstanding. Since the holders of our common stock do not have cumulative voting rights, the holders of a majority of the shares of common stock present, in person or by proxy, will be able to elect all of the members of our Board of Directors. The holders of shares of our common stock do not have preemptive rights or rights to convert their common stock into other securities.

Prior to this offering, our common stock has been thinly traded and there has been no active trading market for our common stock and an active trading market may not develop.

        Following our emergence from bankruptcy, the trading volume of our common stock has been low and reliable market quotations for our common stock have not been available, partially due to the fact that we are not listed on an exchange and our common stock is only traded over-the-counter. An active trading market for our common stock may not develop or, if developed, may not continue, and a holder of any of our securities may find it difficult to dispose of, or to obtain accurate quotations as to the market value of such securities.

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USE OF PROCEEDS

        We will not receive any of the proceeds from the sale of the shares of common stock offered by this prospectus. Any proceeds from the sale of the shares offered by this prospectus will be received by the selling shareholders.


DIVIDEND POLICY

        We currently intend to retain earnings, if any, to finance the growth and development of our business and we do not expect to pay any cash dividends on our common stock in the foreseeable future. Payment of future dividends, if any, will be at the discretion of our Board of Directors and will depend on many factors, including general economic and business conditions, our strategic plans, our financial results and condition, legal requirements and other factors as our Board of Directors deems relevant. In addition, our Revolving Facility and our Notes limit our ability to pay dividends, and we may in the future become subject to debt instruments or other agreements that further limit our ability to pay dividends. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

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CAPITALIZATION

        The following table sets forth, as of June 30, 2010, our cash and cash equivalents and capitalization on an actual basis. This table should be read in conjunction with our historical financial statements and the related notes thereto and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and other financial information that is included elsewhere in this prospectus.

Cash and equivalents(1)

  $ 50,177  
       

Revolving credit facility(2)

  $  

Long term debt

       
 

Senior secured notes

    105,000 (3)
       
   

Total long term debt

    105,000  
       

Stockholders' equity (deficit)

       
 

Common stock ($0.001 par value; 15,000,000 shares authorized; 7,364,573 shares issued and outstanding)

    7  
 

Additional paid in capital

    222,449  
 

Retained earnings (deficit)

    (16,359 )
 

Accumulated other comprehensive loss

    (2,467 )
       
   

Total stockholders' equity (deficit)

    203,630  
       

Total capitalization

  $ 308,630  
       

(1)
Cash and equivalents was approximately $50.2 million at June 30, 2010. Cash and equivalents excludes restricted cash of $12.8 million at June 30, 2010.

(2)
Available borrowing under our $20.0 million Revolving Facility totaled $5.9 million as of June 30, 2010. As of June 30, 2010, there were no amounts drawn against our Revolving Facility, and no outstanding letters of credit issued under our Revolving Facility.

(3)
Excludes $50.0 million aggregate principal amount of Notes issued in August 2010.

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MARKET FOR OUR COMMON STOCK

        Our common stock began trading on the OTCBB on or around May 18, 2010 under the symbol "AVRW.OB." Prior to our emergence from bankruptcy, we were listed on the New York Stock Exchange (the "NYSE") under the symbol "AVR." We were delisted from the NYSE in March 2009 and subsequently traded on the over-the-counter markets and the OTCBB. Upon the effective date of our plan of reorganization on March 15, 2010, approximately 43 million outstanding shares of our common stock were cancelled and our stock ceased trading on the OTCBB and other markets. However, on the effective date of our plan of reorganization our common stock was quoted on Bloomberg, LP and, to our knowledge, received bid and ask quotes ranging from $43.75 to $47.25 per share. After the effective date of our plan of reorganization, beginning in April 2010 until it again began trading on the OTCBB, our common stock was sporadically traded on the over-the-counter markets.

        As of September 7, 2010, the last reported sales price of our common stock on the OTCBB was $22.50 per share of common stock and there were 7,364,573 shares of our common stock outstanding held by approximately 148 holders of record. The following table sets forth the range of high and low bid quotation prices per share of our common stock as reported by the applicable exchange or quotation system. The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions.

 
  Range of Reported
High and Low
Bid Quotations
 
 
  High   Low  

2008

             

First Quarter

  $ 13.08   $ 4.71  

Second Quarter

  $ 6.05   $ 3.75  

Third Quarter

  $ 7.42   $ 3.10  

Fourth Quarter

  $ 3.42   $ 0.34  

2009

             

First Quarter

  $ 0.70   $ 0.09  

Second Quarter

  $ 0.19   $ 0.05  

Third Quarter

  $ 0.35   $ 0.15  

Fourth Quarter

  $ 0.54   $ 0.25  

2010

             

First Quarter

  $ 0.38   $ 0.11  

Second Quarter

  $ 43.75   $ 30.00  

Third Quarter (through September 7, 2010)

  $ 32.95   $ 19.50  

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

        The following tables set forth selected historical consolidated financial data of Aventine Renewable Energy Holdings, Inc. and its subsidiaries on or as of the dates and for the periods indicated. We have derived the selected consolidated financial data as of December 31, 2009, 2008 and 2007 and for the years then ended from the historical audited consolidated financial statements of Aventine Renewable Energy Holdings, Inc. and its subsidiaries prepared in accordance with GAAP, included elsewhere in this prospectus. We have derived the selected consolidated financial data as of December 31, 2006 and 2005 and for the years then ended from the historical audited financial statements of Aventine Renewable Energy Holdings, Inc. and its subsidiaries not included in this prospectus. We derived the unaudited consolidated statement of operations data for the four months ended June 30, 2010, the two months ended February 28, 2010 and for the six months ended June 30, 2009, as well as unaudited consolidated balance sheet data as of June 30, 2010, from our unaudited interim consolidated financial statements included elsewhere in this prospectus. We derived the balance sheet data as of February 28, 2010 and June 30, 2009, from our unaudited interim consolidated financial statements not included in this prospectus. The historical results of Aventine Renewable Energy Holdings, Inc. and its subsidiaries for any prior period are not necessarily indicative of the results to be expected in any future period, and financial results for any interim period are not necessarily indicative of results for a full year.

        In connection with our emergence from reorganization proceedings, we implemented fresh-start accounting in accordance with ASC 852 governing reorganizations. We elected to adopt a convenience date of February 28, 2010 (a month end for our financial reporting purposes) for application of fresh-start accounting. In accordance with the ASC 852 rules governing reorganizations, we recorded largely non-cash reorganization income and expense items directly associated with our reorganization proceedings including professional fees, the revaluation of assets, the effects of our reorganization plan and fresh-start accounting and write-off of debt issuance costs. As a result of the application of fresh-start accounting, our financial statements prior to and including February 28, 2010 represent the operations of our pre-reorganization predecessor company and are presented separately from the financial statements of our post-reorganization successor company. As a result of the application of fresh-start accounting, the financial statements prior to and including February 28, 2010 are not fully comparable with the financial statements for periods on or after February 28, 2010.

        The historical consolidated financial data set forth below should be read in conjunction with, and is qualified in its entirety by, reference to our historical consolidated financial statements and the

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accompanying notes thereto and other financial information contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this prospectus.

 
  Successor   Predecessor  
 
  Four months
ended
June 30,
2010
  Two months
ended
February 28,
2010
  Six months
ended
June 30,
2009
  Year Ended December 31,  
 
  2009   2008   2007   2006   2005  

Statement of Operations Data:

                                                 

(in thousands, except per share amounts)

                                                 

Net sales

  $ 133,878   $ 77,675   $ 354,657   $ 594,623   $ 2,248,301   $ 1,571,607   $ 1,592,420   $ 935,468  

Cost of goods sold

    (132,766 )   (66,686 )   (375,980 )   (585,904 )   (2,239,340 )   (1,497,807 )   (1,460,806 )   (848,053 )
                                   

Gross profit

    1,112     10,989     (21,323 )   8,719     8,961     73,800     131,614     87,415  

Selling, general and administrative expenses

    (14,286 )   (4,608 )   (16,691 )   (26,694 )   (35,410 )   (36,367 )   (28,328 )   (22,500 )

Demobilization costs associated with expansion projects

                    (9,874 )            

Impairment of plant development costs

                    (1,557 )            

Other income (expense)

    (1,659 )   (515 )   173     (1,510 )   2,936     1,113     3,389     989  
                                   

Operating income (loss)

    (14,833 )   5,866     (37,841 )   (19,485 )   (34,944 )   38,546     106,675     65,904  

Other income (expense):

                                                 

Income from termination of marketing agreements

            10,176     10,176                  

Loss on the sale of auction rate securities

                    (31,601 )            

Interest income

    15         11     11     3,040     12,432     4,771     2,218  

Interest expense(1)

    (3,100 )   (1,422 )   (11,002 )   (14,697 )   (5,077 )   (16,240 )   (9,348 )   (16,510 )

Loss on marketing alliance investment

                    (4,326 )            

Loss on early extinguishment of debt

                            (14,598 )    

Gain (loss) on derivative transactions

    439         1,218     1,219     17,110     (78 )   3,654     1,781  

Other non-operating income

    210                              
                                   

Income (loss) before reorganization items and income taxes

    (17,269 )   4,444     (37,438 )   (22,776 )   (55,798 )   34,660     91,154     53,393  

Reorganization items

        (20,282 )   (42,749 )   (32,440 )                

Gain due to Plan effects

        136,574                          

Loss due to fresh start accounting adjustments

        (387,655 )                        
                                   

Income (loss) before income taxes

    (17,269 )   (266,919 )   (80,187 )   (55,216 )   (55,798 )   34,660     91,154     53,393  

Income tax expense (benefit)

    (910 )   (626 )   (6,685 )   (8,956 )   (7,472 )   (477 )   31,685     18,807  
                                   

Net income (loss)

  $ (16,359 ) $ (266,293 ) $ (73,502 ) $ (46,260 ) $ (48,326 ) $ 35,137   $ 59,469   $ 34,586  

Net income (loss) attributable to non-controlling interest

                    (1,230 )   1,338     4,568     2,404  
                                   

Net income (loss) attributable to controlling interest

  $ (16,359 ) $ (266,293 ) $ (73,502 ) $ (46,260 ) $ (47,096 ) $ 33,799   $ 54,901   $ 32,182  

Per Share Data:

                                                 

Income (loss) per common share-basic

  $ (1.87 ) $ (6.14 ) $ (1.71 ) $ (1.08 ) $ (1.12 ) $ 0.81   $ 1.43   $ 0.93  

Basic weighted-average common shares

    8,581     43,401     42,968     42,968     42,136     41,886     38,411     34,686  

Income (loss) per common share-diluted

  $ (1.87 ) $ (6.14 ) $ (1.71 ) $ (1.08 ) $ (1.12 ) $ 0.80   $ 1.39   $ 0.89  

Diluted weighted-average common and common equivalent shares

    8,581     43,401     42,968     42,968     42,136     42,351     39,639     36,052  

Other Data (unaudited):

                                                 

(in thousands, except per bushel and per gallon amounts)

                                                 

EBITDA(2)

  $ (10,897 ) $ (263,164 ) $ (62,254 ) $ (26,164 ) $ (38,009 ) $ 49,708   $ 94,877   $ 67,555  

Adjusted EBITDA(2)

  $ (8.016 ) $ 8,475   $ (17,916 ) $ 8,812   $ 878   $ 56,913   $ 115,953   $ 69,485  

Gallons sold

    64,098     31,478     173,623     277,471     935,986     690,171     695,784     529,836  

Capital expenditures

  $ 21,498   $ 2,086   $ 901   $ 2,279   $ 265,878   $ 235,211   $ 76,499   $ 20,672  

Average price per gallon of ethanol sold

  $ 1.63   $ 1,91   $ 1.69   $ 1.75   $ 2.22   $ 2.08   $ 2.18   $ 1.63  

Average price of corn per bushel

  $ 3.57   $ 3,66   $ 4.17   $ 3.87   $ 5.02   $ 3.76   $ 2.41   $ 2.08  

Balance Sheet Data:

                                                 

(in thousands, at period end)

                                                 

Total assets

  $ 341,815   $ 364,305   $ 699,276   $ 713,675   $ 799,459   $ 762,185   $ 408,136   $ 221,977  

Total debt(3)

  $ 105,000   $ 110,252   $ 42,765   $ 42,765   $ 352,200   $ 300,000       $ 161,514  

Stockholders' equity (deficit)

  $ 203,630   $ 219,923   $ 237,665   $ 267,532   $ 308,796   $ 343,871   $ 304,163   $ (20,654 )

(1)
Contractual interest expense was $4.4 million, $6.4 million, and $36.6 million for the four months ended June 30, 2010, two months ended February 28, 2010 and the year ended December 31, 2009, respectively.

(2)
EBITDA and Adjusted EBITDA are non-GAAP financial measures. Our definition of EBITDA and Adjusted EBITDA and a reconciliation of net income (loss) to EBITDA and Adjusted EBITDA is provided in note (1) under "Summary—Aventine Energy Renewable Holdings, Inc.—Summary Historical Consolidated Financial Data."

(3)
Prior to March 1, 2010, total debt includes amounts outstanding under: 1) our revolving credit agreement; 2) our senior unsecured notes in 2007 and 2008; 3) our debtor-in-possession debt facility; and 4) our previously outstanding senior, secured floating rate notes. The senior unsecured notes are reflected in pre-petition liabilities subject to compromise at December 31, 2009. On and after March 1, 2010, total debt includes amounts outstanding under: 1) our Revolving Facility; 2) the Notes; and 3) our short-term note payable to Kiewit Energy Company.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

        The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the "Selected Financial Information" section of this prospectus and our financial statements and the related notes and other financial information included elsewhere in this prospectus. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results and timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under "Risk Factors" and elsewhere in this prospectus.

Company Overview

        We are a producer and marketer of corn-based fuel-grade ethanol in the U.S. We market and distribute ethanol to many of the leading energy and trading companies in the U.S. In addition to producing ethanol, our facilities also produce several co-products such as distillers grain, corn gluten meal and feed, corn germ and brewers' yeast, which generate incremental revenue and allow us to help offset a significant portion of our corn costs.

Recent Events

        Notes Offering.    On August 19, 2010, we issued and sold $50.0 million in aggregate principal amount of our Notes in a transaction exempt from the registration requirements under the Securities Act, resulting in gross proceeds to us of approximately $51.0 million.

        First Amendment to Secured Revolving Credit Facility.    On August 6, 2010, we and our subsidiaries, as borrowers, entered into the First Amendment with the financial institutions party thereto as lenders, and PNC. The First Amendment amends the Revolving Credit Agreement by increasing the letter of credit sublimit under the Revolving Credit Agreement from $12.0 million to $17.0 million. The First Amendment also modifies the capital expenditure limitations applicable to us and our subsidiaries under the Revolving Credit Agreement and our daily inventory reporting requirements to permit PNC to agree not to require daily reporting by the borrowers of in-transit inventory.

        Acquisition of Canton, Illinois Facility.    On August 6, 2010, we and Riverland entered into the Purchase Agreement pursuant to which we acquired substantially all of the assets, and assumed specified liabilities, of Riverland for a purchase price of $16.5 million. The assets comprise the Canton facility, and include real property at the plant site as well as surrounding parcels.

        Debt Commitment Letter.    On August 2, 2010, we entered into the Debt Commitment Letter with Citi, under which Citi has agreed, at a subsequent time, to use its best efforts to arrange a syndicate of lenders that will provide us with the New Term Loan Facility, and to act as lead arranger, bookrunner, administrative agent and collateral agent for the New Term Loan Facility, on the terms and subject to the conditions set forth in the Debt Commitment Letter. Consummation of the debt financing is subject to various conditions set forth in the Debt Commitment Letter, including the absence of certain "material adverse effects" with respect to us and our subsidiaries, taken as a whole. We are under no obligation to enter into any such debt financing and cannot assure you that we will enter into any such financing transaction on terms acceptable to us, if at all.

Executive Summary—Results of Operations

        The following discussion summarizes the significant factors affecting the consolidated operating results of the Company for the six month periods ended June 30, 2010 and 2009 and years ended December 31, 2009 and 2008. This discussion should be read in conjunction with our condensed

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consolidated financial statements and notes to our condensed consolidated financial statements contained herein.

        We emerged from bankruptcy on March 15, 2010. On March 15, 2010, we implemented fresh-start accounting in accordance with ASC 852. Thus, the consolidated financial statements prior to March 1, 2010 reflect results based upon the historical cost basis of the Company while the post-emergence consolidated financial statements reflect the new basis of accounting incorporating the fair value adjustments made in recording the effects of fresh-start reporting. Therefore, the post-emergence periods are not comparable to the pre-emergence periods. However, for discussions on the results of operations, we have combined the results for the six months ended June 30, 2010. The combined period has been compared to the six months ended June 30, 2009. We believe that the combined financial results provide management and investors a better perspective of our core business and on-going operational financial performance and trends for comparative purposes.

        Our revenues are principally derived from the sale of ethanol and from the sale of co-products (corn gluten feed and meal, corn germ, CCDS, DDGS, WDGS, carbon dioxide, and brewers' yeast) that we produce as by-products during the production of ethanol at our plants.

        We generated a net loss for the first half of 2010 of $282.7 million, as compared to a net loss of $73.5 million in the first half of 2009. The loss in 2010 is primarily attributable to adjustments required to report assets and liabilities at fair value upon emergence from bankruptcy. We generated a net loss of $46.3 million in 2009, as compared to a net loss of $47.1 million in 2008. The 2009 net loss was significantly increased by $32.4 million in reorganization items resulting from the Company's Chapter 11 bankruptcy filing. The 2008 net loss was increased as a result of $33.2 million in nonrecurring losses comprised of a $31.6 million loss related to the sale of our portfolio of auction rate securities and a $1.6 million impairment loss pertaining to the development costs of a second dry mill ethanol plant on our Pekin site. Revenue in the first half of 2010 decreased to $211.6 million as compared to $354.7 million in the first half of 2009. Revenue in 2009 decreased to $594.6 million as compared to $2.2 billion in 2008.

        Commodity spread, defined as gross ethanol selling price per gallon less net corn cost per gallon, increased from $0.57 per gallon in the first half of 2009 to $0.86 per gallon in the first half of 2010. Commodity spread decreased from $1.00 per gallon in 2008 to $0.79 per gallon in 2009. The average sales price per gallon of ethanol increased in the first half of 2010 to $1.72 per gallon from the $1.69 average received in the first half of 2009. The average sales price per gallon of ethanol decreased in 2009 to $1.75 from the $2.22 average received in 2008. Corn costs during the first half of 2010 averaged $3.60 per bushel, as compared to $4.17 per bushel in the first half of 2009. Corn costs in 2009 averaged $3.87 per bushel, as compared to $5.02 per bushel in 2008. Conversion cost in the first half of 2010 was $0.52 per gallon as compared to $0.50 per gallon in the first half of 2009. Conversion cost in 2009 was $0.49 per gallon as compared to $0.70 per gallon in 2008.

        Gallons of ethanol sold in the first half of 2010 decreased to 95.6 million gallons, as compared to 173.6 million gallons in the first half of 2009. Gallons of ethanol sold in 2009 decreased to 277.5 million from 936.0 million in 2008. With severely declining gross profit margins and general liquidity stress due to frozen credit markets, we negotiated termination agreements with our marketing alliance partners and began to rationalize our distribution network to primarily focus on sales of our equity production beginning in the fourth quarter of 2008. We completed the termination of our marketing alliance and scaled back our purchase/resale program during the first quarter of 2009. Ethanol production for the six months ended June 30, 2010 and the year ended December 31, 2009 totaled 94.0 million gallons and 197.5 million gallons, compared to 99.2 million gallons and 188.8 million gallons in the six months ended June 30, 2009 and the year ended December 31, 2008, respectively. Gross profit for the six months ended June 30, 2010 increased substantially to $12.1 million from $(21.3) million in the six

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months ended June 30, 2009. Gross profit for the year ended December 31, 2009 decreased slightly to $8.7 million from $9.0 million in the year ended December 31, 2008.

        Our inventory is valued based upon a weighted average of our cost to produce ethanol and the price we pay for ethanol that we purchase from other producers. Due to the dissolution of the marketing alliance in early 2009, we no longer make purchases of ethanol from alliance partners but continue to engage in purchase/resale transactions, as needed, to fulfill our sales commitments. Changes, either upward or downward, in our purchased cost of ethanol or our own production costs, will cause the inventory value to fluctuate from period to period, perhaps significantly. These changes in value flow through our statement of operations as the inventory is sold and can significantly increase or decrease our profitability.

        Other income (loss) was a loss of $2.2 million in the first half of 2010 compared to income of $0.2 million in the first half of 2009. The loss in the first half of 2010 included $0.8 million of expense related to penalties owed for failure to complete the Aurora West expansion facility by July 1, 2009, $1.1 million of expense related to a contract amendment, and $0.5 million in utility demand charges at our Mt. Vernon ethanol expansion facility. In the first half of 2009, the Company recognized income from the termination of marketing agreements with alliance partners totaling $10.2 million.

        We have significantly reduced our hedging activity after the first quarter of 2009. Our gain on derivative transactions has decreased from $1.2 million for the first half of 2009 to $0.4 million for the first half of 2010.

        Reorganization items of $20.3 million in the first half of 2010 were comprised primarily of professional fees directly related to the reorganization and a provision for rejected executory contracts and leases. There were $42.7 million in reorganization items in the first half of 2009. Reorganization items of $(10.3) million during the remainder of 2009 were again comprised primarily of professional fees directly related to the reorganization and a provision for rejected executory contracts and leases.

        The gain due to plan effects in the first half of 2010 of $136.6 million, related to implementation of the plan of reorganization, consisted of $144.0 million of liabilities subject to compromise which were discharged upon emergence from bankruptcy less $5.8 million of unamortized debt issuance costs on the 10.0% senior unsecured notes due 2017 issued March 27, 2007 (the "Old Notes") and $1.6 million related to write-off of prepaid directors and officer insurance. There were no gains due to plan effects in the first half of 2009.

        The loss due to fresh-start accounting adjustments of $387.7 million in the first half of 2010 consisted of adjustments required to report assets and liabilities upon emergence from bankruptcy at fair value.

General

        The following general factors should be considered in analyzing our results of operations:

Variability of Gross Profit

        Our gross profit has fluctuated and may continue to fluctuate substantially from period to period. Gross profit from ethanol sales is mainly affected by changes in selling prices for ethanol, along with the cost of corn, freight and the cost to convert corn to ethanol. The rise and fall of ethanol and corn prices affects the levels of our costs of goods, gross profit and inventory values, even in the absence of any increases or decreases in business activity. Selling prices for ethanol are affected principally by industry oversupply concerns, the price and availability of competing and complementary fuels and the price of corn. All of these factors are beyond our control.

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        Our most volatile manufacturing costs are natural gas and corn. See "Risk Factors—Our business is dependent upon the availability and price of corn. Significant disruptions in the supply of corn will materially affect our operating results. In addition, since we generally cannot pass on increases in corn prices to our customers, continued periods of historically high corn prices will also materially adversely affect our operating results," and "—The market for natural gas is subject to market conditions that create uncertainty in the price and availability of the natural gas that we utilize in our manufacturing process." Since both natural gas and ethanol are energy-related products, there has been significant, although not perfect, correlation between their market prices. As a result, at times when natural gas prices had increased, thereby increasing our costs, ethanol prices have typically increased, thereby increasing our revenues and offsetting some of the impact on our results of operations.

Conversion Costs

        Conversion costs per gallon are an important metric in determining our profitability. Conversion costs represent the cost of converting corn into ethanol, and include production salaries, wages and stock compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs. It does not include depreciation and amortization expense.

Summary of Critical Accounting Policies

        We base this discussion and analysis of results of operations, cash flow and financial condition on our consolidated financial statements, which have been prepared in accordance with GAAP.

        The accompanying historical consolidated financial data, as of and from the years ended 2009, 2008 and 2007 and the quarter ended June 30, 2009 do not purport to reflect or provide for the consequences of our Chapter 11 proceedings. In particular, the financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be paid out for claims or contingencies, or the status and priority thereof; (iii) as to shareowners' equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business.

        In accordance with GAAP, we have applied authoritative guidance of ASC 852, in preparing the consolidated financial statements. This guidance requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses (including professional fees), realized gains and losses and provisions for losses that were realized or incurred in the bankruptcy proceedings are recorded in reorganization items on the accompanying condensed consolidated statements of operations. In addition, pre-petition obligations that were impacted by the bankruptcy reorganization process have been classified on the consolidated balance sheet at December 31, 2009 in "pre-petition liabilities subject to compromise." These liabilities are reported at the amounts that were expected to be allowed by the Bankruptcy Court, even if they may be (or have been) settled for lesser amounts. For information on the bankruptcy reorganization process, see Note 2 of our 2009 annual financial statements and Note 2 of our second quarter of 2010 quarterly financial statements.

Share-based Compensation Expense

        Effective January 1, 2006, we adopted, on a modified prospective transition method, Accounting Standards Codification 718, Compensation—Stock Compensation ("ASC 718"), which requires measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including stock options, based on fair values. Share-based compensation

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expense recognized is based on the value of the portion of share-based payment awards that is ultimately expected to vest. Share-based compensation expense recognized in our consolidated statements of operations for the years ended December 31, 2009, 2008 and 2007 include compensation expense for unvested share-based payment awards granted prior to December 31, 2005, based on the grant date fair value estimated in accordance with the minimum value method as outlined in ASC 718, and compensation expense for the share-based payment awards granted subsequent to December 31, 2005 based on the grant date fair value estimated in accordance with the provisions of ASC 718. In conjunction with the adoption of ASC 718, we elected to attribute the value of share-based compensation to expense over the periods of requisite service using the straight-line method.

        Upon adoption of ASC 718, we elected to value our share-based payment awards granted beginning in fiscal year 2006 using a form of the Black-Scholes option-pricing model (the "Option-Pricing Model"), which was previously used to calculate stock-based compensation expense using the minimum value method as outlined in ASC 718. The determination of fair value of share-based payment awards on the date of grant using the Option Pricing Model is affected by our stock price as well as the input of other subjective assumptions, of which the most significant are expected stock price volatility, the expected pre-vesting forfeiture rate and the expected option term (the amount of time from the grant date until the options are exercised or expire). Expected volatility is normally calculated based upon actual historical stock price movements over the expected option term. Since we have no considerable history of stock price volatility as a public company at the time of the grants, we calculated volatility by considering, among other things, the expected volatilities of public companies engaged in similar industries. Pre-vesting forfeitures prior to June 30, 2008 were estimated using a 3% forfeiture rate. We adjusted the forfeiture rate to 6.4%, 10.7%, 14.2%, and 20.0% as of July 1, 2008, January 1, 2009, July 1, 2009, and October 1, 2009, respectively, to reflect our experience with actual forfeitures. The expected option term is calculated using the "simplified" method permitted by SAB 107. Our options have characteristics significantly different from those of traded options, and changes in the assumptions can materially affect the fair value estimates.

Inventory

        Inventories are stated at the lower of cost or market. Cost is determined using a weighted-average first-in-first-out ("FIFO") method for gallons produced at our plants, gallons purchased from our marketing alliance partners and other gallons purchased for resale. In assessing the ultimate realization of inventories, we perform a periodic analysis of market price and compare that to our weighted-average FIFO cost to ensure that our inventories are properly stated at the lower of cost or market.

Derivatives and Hedging Activities

        Our operations and cash flows are subject to fluctuations due to changes in commodity prices. We use derivative financial instruments from time-to-time to manage commodity prices. Derivatives used are primarily commodity futures contracts, swaps and option contracts.

        We apply the provisions of Accounting Standards Codification 815, Derivatives and Hedging ("ASC 815"), for our derivatives. These derivative contracts are not designated as hedges and, therefore, except for contracts that meet the normal purchase or normal sale exception, are marked to market each period, with corresponding gains and losses recorded in other non-operating income (loss). The fair value of these derivative contracts are recognized in other current assets or other current liabilities in the consolidated balance sheets, net of any cash received from the relevant brokers.

        ASC 815 requires a company to evaluate contracts to determine whether the contracts are derivatives. Certain contracts that meet the literal definition of a derivative under ASC 815 may be exempted from the accounting and reporting requirements of ASC 815 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities

35


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expected to be used or sold over a reasonable period in the normal course of business. The Company elects to designate its forward purchases of corn and forward sales of ethanol as normal purchases and sales under ASC 815. Accordingly, these contracts are not recorded in our financial results until performance under them occurs.

Income Taxes

        Under Accounting Standards Codification 740, Income Taxes ("ASC 740"), deferred tax liabilities and assets are recorded for the expected future tax consequences of events that have been recognized in our financial statements or tax returns. Property, plant and equipment, stock-based compensation expense and investments in marketing alliance partners are the primary sources of these temporary differences. Deferred income taxes also includes net operating loss and capital loss carryforwards. The Company establishes valuation allowances to reduce deferred tax assets to amounts it believes are realizable and contingency reserves for implemented tax planning strategies. These valuation allowances and contingency reserves are adjusted based upon changing facts and circumstances.

Pension and Postretirement Benefit Costs

        Net pension and postretirement costs were $0.7 million for the year ended December 31, 2009 and $0.3 million for the year ended December 31, 2008. Total estimated pension and postretirement expense in 2010 is expected to be similar to previous years. These expenses are primarily included in cost of goods sold. We made contributions to our defined benefit pension plan in 2009, 2008 and 2007 of $0.2 million, $0.9 million, and $0.5 million, respectively. In 2010, we expect to make contributions totaling $0.8 million to our defined benefit plan.

        Our pension and postretirement benefit costs are developed from actuarial valuations. Inherent in these valuations are key assumptions including discount rates and expected long-term rates of return on plan assets. Material changes in our pension and postretirement benefit costs may occur in the future due to changes in these assumptions, changes in the number of plan participants, changes in the level of benefits provided, changes to the level of contributions to these plans and other factors.

        We determine our actuarial assumptions for our pension and post retirement plans, after consultation with our actuaries, on December 31 of each year to calculate liability information as of that date and pension and postretirement expense for the following year. The discount rate assumption is determined based on a spot yield curve that includes bonds that are rated Corporate AA or higher with maturities that match expected benefit payments under the plan.

        The expected long-term rate of return on plan assets reflects projected returns for the investment mix that have been determined to meet the plan's investment objectives. The expected long-term rate of return on plan assets is selected by taking into account the expected weighted averages of the investments of the assets, the fact that the plan assets are actively managed to mitigate downside risks, the historical performance of the market in general and the historical performance of the retirement plan assets over the past ten years.

Revenue Recognition

        Revenue is generally recognized when title to products is transferred to an unaffiliated customer as long as the sales price is fixed or determinable and collectability is reasonably assured. For the majority of sales, this generally occurs after the product has been offloaded at the customers' site. For others, the transfer of title occurs at the shipment origination point. The majority of sales are invoiced at the final per unit price which may be a previously contracted fixed price or a market price at the time of shipment. Other sales are invoiced and the initial receipts are collected based upon a provisional price, and such sales are adjusted to a final price based upon a monthly-average spot market price. Sales are made under normal terms and usually do not require collateral.

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        The Company has marketed ethanol for other third-party producers. Revenues from such non-Company produced gallons are generally recorded on a gross basis in the accompanying statements of operations, as the Company takes title to the product, assumes all risks associated with the purchase and sale of such gallons and is considered the primary obligor on the sale. Transactions entered into with the same counterparty which have been negotiated in contemplation of one another are recorded on a net basis.

        The majority of sales are based upon a delivered price, which includes a cost for freight. In such cases, the sales price, including the cost of delivery plus any respective motor fuel excise taxes, is invoiced and included in revenue. If title transfers at the shipment origination point, the customer generally is responsible for freight costs, and the Company does not recognize such freight costs in its financial statements.

Fresh-Start Accounting

        As required by GAAP, in connection with emergence from Chapter 11 reorganization proceedings, we adopted the fresh-start accounting provisions of ASC 852 effective February 28, 2010. Under ASC 852, the reorganization value represents the fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for our assets immediately after restructuring. The reorganization value is allocated to the respective assets. Liabilities, other than deferred taxes and severance benefits, are stated at present values of amounts expected to be paid.

        Fair values of assets and liabilities represent our best estimates based on our appraisals and valuations which incorporated industry data and trends and relevant market rates and transactions available to us at the time. The estimate of reorganization equity value was determined by Company management with assistance from an independent financial advisor, who developed the reorganization equity value using a combination of the following three measurement methodologies: 1) comparable public company analysis, 2) discounted cash flow analysis, and 3) precedent transactions analysis. This amount was determined based, in part, on economic, competitive and general business conditions prevailing at the time. These estimates and assumptions are inherently subject to significant uncertainties and contingencies beyond our reasonable control.

        The significant assumptions related to adjusting our assets and liabilities to fair value in connection with fresh-start accounting include the following:

        Cash, Accounts Receivable, Prepaid Assets and Other Current Assets, Accrued Liabilities, and Other Current Liabilities—We evaluated the fair value of financial instruments represented in current assets and current liabilities, including cash, accounts receivable, prepaid assets and other current assets, accrued liabilities, and other current liabilities. Based upon our evaluations, we concluded that the carrying value approximates fair value of these financial instruments due to their short maturities or variable-rate nature of the respective balances.

        Restricted Cash, and Other Long-Term Liabilities—We evaluated the fair value of restricted cash and other long-term liabilities. The restricted cash balances are held in interest-bearing accounts and we therefore concluded that the carrying value approximates fair value. The other long-term liabilities principally represent company obligations related to pension and retiree medical costs. Such liabilities are calculated using various assumptions including an assumed discount rate which we believe is reasonable, and we therefore concluded that carrying value of such long-term liabilities approximates fair value.

        Inventories—Inventories consist primarily of agricultural and energy-related commodities including corn, ethanol, and coal. The fair value of these commodities was determined through reference to prices that were publicly available at the time, as adjusted for physical location.

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        Property, plant and equipment—Property, plant and equipment was valued at fair value of approximately $208.8 million as of February 28, 2010. The Company determined fair value with the assistance of an independent valuation firm. In establishing fair value for the vast majority of the Company's property, plant and equipment, the cost approach was utilized. The cost approach considers the amount required to replace an asset by constructing or purchasing a new asset with similar utility, then adjusts the value in consideration of all forms of depreciation as of the appraisal date as described below:

    Physical depreciation—the loss in value or usefulness attributable solely to use of the asset and physical causes such as wear and tear and exposure to the elements.

    Functional obsolescence—a loss in value is due to factors inherent in the asset itself and due to changes in technology, design or process resulting in inadequacy, overcapacity, lack of functional utility or excess operating costs.

    Economic obsolescence—loss in value by unfavorable external conditions such as economics of the industry or geographic area, or change in ordinances.

The cost approach relies on management's assumptions regarding current material and labor costs required to rebuild and repurchase significant components of our property, plant and equipment along with assumptions regarding the age and estimated useful lives of our property, plant and equipment.

        Other Assets—Other assets include a long-term deposit for utilities against which the Company may apply certain future natural gas transportation charges. The fair value of this deposit was determined based upon a discounted cash flow model for which the significant inputs include the Company's estimated purchase timing and amount of natural gas, and the discount rate estimated to be 13%. If the Company had applied a discount rate of 1% higher or lower, the fair value of the asset would have decreased or increased by $168 thousand or $177 thousand, respectively.

        Accounts Payable—Accounts payable include an estimated liability associated with an off-market coal purchase contract which continues throughout 2010. The fair value of this contract was determined through reference to coal prices that were publicly available at the time, as adjusted for physical location. This liability will be amortized to income as the related coal purchases affect the cost of production. For other accounts payable items, we evaluated such liabilities to determine fair value and concluded that the carrying value approximates fair value of these financial instruments due to their short maturities or variable-rate nature of the respective balances.

        Long-Term Debt—Long-term debt was valued at fair value with the assistance of an independent valuation firm based on an analysis of market interest rates for guideline companies with similar debt and terms, interest rates for companies recently emerged from bankruptcy, and interest rates based on a synthetic debt rating. Based on this analysis, we determined that a range of market interest rate for our $105 million of Notes would be from 11.5% to 14.5%. Based on the stated rate of our Notes of 13% combined with the option to pay a portion of the interest in kind, we deemed the fair value to be the face value of the Notes of $105 million. If the interest rate was 1% higher or lower, the fair value of the debt would have increased or decreased by $1.2 million respectively.

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Results of Operations

For the Six Months Ended June 30, 2010 Compared to the Six Months Ended June 30, 2009

        Total gallons of ethanol sold in the first half of 2010 decreased to 95.6 million gallons, versus 173.6 million gallons sold in the first half of 2009. Gallons of ethanol were sourced as follows:

 
  For the Three Months Ended June 30,  
 
  2010   2009   Increase/
(Decrease)
  % Increase/
(Decrease)
 
 
  (In thousands of gallons, except for percentages)
 

Equity production

    94,014     99,152     (5,138 )   (5.2 )%

Marketing alliance purchases

        12,898     (12,898 )   (100.0 )%

Purchase/resale

    705     29,780     (29,075 )   (97.6 )%

Decrease (increase) in inventory

    857     31,793     (30,936 )   N.M.*  
                   

Total

    95,576     173,623     (78,047 )   (45.0 )%
                   

*
Not meaningful

        Net sales in the first half of 2010 decreased 40.3% from the first half of 2009. Net sales were $211.6 million in the first six months of 2010 versus $354.7 million in the first six months of 2009. Overall, the decrease in net sales was primarily the result of less supply available as we terminated our marketing alliance and significantly reduced purchase/resale supply operations, partially offset by an increase in the average sales price of ethanol sold. The reduction in equity production between 2010 and 2009 is primarily attributable to timing differences and the length of plant maintenance shutdowns. Ethanol prices averaged $1.72 per gallon in the first half of 2010 versus $1.69 in the first half of 2009.

        Co-product revenues for the first half of 2010 totaled $46.9 million, a decrease of $2.1 million or 4.3%, from the first half 2009 total of $49.0 million. Co-product revenues decreased during the first half of 2010 as a result of lower sales volumes. In the first half of 2010, we sold 478.7 thousand tons, versus 555.1 thousand tons in the first half of 2009. Co-product revenues, as a percentage of corn costs, rose to 36.6% during the first half of 2010, versus 31.9% in the first half of 2009.

        Cost of goods sold for the first six months ended June 30, 2010 was $199.5 million, compared to $376.0 million for the six months ended June 30, 2009, a decrease of $176.5 million, or 46.9%. As a percentage of net sales, cost of goods sold decreased to 94.3% of sales from 106.0% of sales in the first half of 2009. Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of freight and logistics to ship ethanol and co-products, the cost of ethanol sold from inventory, the cost of motor fuel taxes which have been billed to customers and, prior to the second quarter of 2009, the cost of purchased ethanol. The decrease in total cost of goods sold is principally the result of lower volumes of ethanol purchased as a result of the termination of our marketing alliance and significantly reduced purchase/resale program, and lower corn costs, freight costs, depreciation, and motor fuel taxes.

        Purchased ethanol in the first half of 2010 totaled $1.2 million, versus $78.3 million in the first half of 2009. The decrease in purchased ethanol resulted from the termination of our marketing alliance and scaled-back purchase/resale programs along with a decrease in the cost per gallon of ethanol purchased.

        Production costs include corn costs, conversion costs (defined as the cost of converting the corn into ethanol, and includes production salaries, wages and stock-based compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs) and depreciation. Corn costs in the first six months of 2010 totaled $128.0 million, or $3.60 per bushel, versus $153.8 million, or $4.17 per bushel, in the

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first six months of 2009. Our average corn costs in the first half of 2010 were lower than the Chicago Board of Trade ("CBOT") average price of $3.62 during the same period. The decrease in corn costs is principally due to lower corn prices.

        Conversion costs for the first half of 2010 decreased to $48.6 million from $49.0 million for the first half of 2009. The total dollars spent on conversion costs decreased year over year principally as a result of lower costs for utilities, chemicals and other supplies which have decreased as a result of lower petroleum prices. The conversion cost per gallon increased year over year to $0.52 per gallon in the first half of 2010 versus $0.50 per gallon in the first half of 2009. Conversion cost per gallon is affected by both dollars spent on conversion of corn to ethanol and also on the number of gallons of ethanol produced.

        Freight/logistics costs were down significantly on a per gallon basis in the first half of 2010 from the first half of 2009. Freight/logistics costs in the first half of 2010 were $0.12 per gallon as compared to $0.19 per gallon in the first half of 2009. Freight/logistics dollars spent decreased in the first six months of 2010 to $11.1 million from $33.3 million in the first six months of 2009 as a result of lower volumes shipped, the termination of fixed price terminal obligations, and lower costs for leased railcars.

        Depreciation in the first half of 2010 totaled $5.6 million, versus $6.9 million in the first half of 2009. No motor fuel taxes were incurred in the first half of 2010 versus $5.6 million in the first half of 2009. The cost of motor fuel taxes is recovered through billings to customers and, was $0 in the first half of 2010 because we did not do business in states requiring us to pay motor fuel taxes.

        SG&A expenses were $18.9 million in the first six months of 2010 as compared to $16.7 million in the first six months of 2009. The higher expense in the first half of 2010 primarily relates to increases in salaries and wages of $0.9 million and salaried stock-based compensation of $1.7 million.

        During the first six months of 2009, we recognized income from the termination of marketing agreements with our former alliance partners totaling $10.2 million.

        Interest expense in the first half of 2010 was $4.5 million, as compared to $11.0 million in the first half of 2009. Interest expense in the first half of 2010 included $4.0 million of interest expense related to our Notes, pre-petition secured revolving credit facility interest expense of $0.6 million, interest expense on our debtor-in-possession debt facility of $0.5 million, and $0.4 million for amortization of deferred financing fees, reduced by capitalized interest of $1.0 million. Interest expense in the first half of 2009 included $8.1 million of interest expense related to our Old Notes (compared to contractual interest of $15 million), pre-petition amended secured revolving credit facility interest expense of $1.0 million, interest expense on our debtor-in-possession debt facility of $0.5 million, and $1.4 million for amortization of deferred financing fees.

        Gain (loss) on derivative transactions for the first half of 2010 includes $0.4 million of realized net gains on corn and ethanol derivative contracts versus net realized and unrealized gains in the first half of 2009 of $1.2 million. We did not have any open derivative positions at the end of June 2009. We do not mark to market forward physical contracts to purchase corn or sell ethanol.

        Our effective tax rate differs from the statutory U.S. federal income tax rate for the four months ended June 30, 2010, two months ended February 28, 2010, and the six months ended June 30, 2009 principally due to the impact of state taxes (net of federal benefit), non-includable reorganization income, non-deductible reorganization expenses, tax deductible goodwill, increases in valuation allowances, and other permanent differences between book and tax.

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Table of Contents

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

        Total gallons sold in 2009 were 277.5 million gallons, versus 936.0 million gallons sold in 2008, a decrease of 658.5 million gallons. Ethanol gallons sourced were as follows:

 
  For the Year Ended December 31,  
 
  2009   2008   Increase/
(Decrease)
  % Increase/
(Decrease)
 
 
  (In thousands, except for percentages)
 

Equity production

    197,498     188,764     8,734     4.6 %

Marketing alliance purchases

    30,858     505,254     (474,396 )   (93.9 )%

Purchase/resale

    35,506     249,028     (213,522 )   (85.7 )%

Decrease (increase) in inventory

    13,609     (7,060 )   20,669     N.M.*  
                   

Total

    277,471     935,986     (658,5155 )   (70.4 )%
                   

*
Not meaningful

        Net sales for 2009 were significantly lower at $594.6 million for 2009 versus $2.2 billion in 2008. With severely declining gross profit margins and general liquidity stress due to frozen credit markets, we negotiated termination agreements with our marketing alliance partners and began to rationalize our distribution network to primarily focus on sales of our equity production beginning in the fourth quarter of 2008. We completed the disbanding of our marketing alliance and scaled back our purchase/resale program during the first quarter of 2009. The average gross selling price of ethanol in 2009 decreased to $1.75 per gallon, from the $2.22 received in 2008.

        Co-product revenue for 2009 totaled $98.0 million, a decrease of $30.5 million or 23.8%, from the 2008 total of $128.5 million. Co-product revenue decreased during 2009 versus 2008 principally from a decrease in co-product pricing due to lower corn prices. Co-product pricing tends to follow the price of corn since the co-products are a substitute for corn as an animal feedstock. We sold 1.1 million tons of co-products in both 2009 and 2008. Co-product revenues, as a percentage of corn costs, were 34.1% during 2009, versus 35.9% in 2008. Co-product returns, as a percentage of corn costs, decreased in 2009 compared to 2008 as the co-product prices decreased more than the decrease in corn costs.

        Cost of goods sold for 2009 was $585.9 million, a significant decrease from the $2.2 billion in 2008. Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from marketing alliance partners, the cost of purchasing ethanol and bio-diesel from other producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers.

        Purchased ethanol in 2009 totaled $138.5 million, versus approximately $1.5 billion in 2008. The decrease in purchased ethanol results from a decrease in the number of gallons of ethanol purchased from marketing alliance partners as well as a decrease in purchase/resale gallons purchased, along with a decrease in the cost per gallon of ethanol purchased. In 2009, we purchased 66.4 million gallons of ethanol at an average cost of $1.56 per gallon as compared to 754.3 million gallons of ethanol at an average cost of $2.04 in 2008.

        Production costs include corn costs, conversion costs (defined as the cost of converting the corn into ethanol, and includes production salaries, wages and stock compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs) and depreciation. Corn costs in 2009 totaled $287.1 million or $3.87 per bushel, versus $358.4 million, or $5.02 per bushel in 2008. The decrease in corn costs is due to the record high corn prices in 2008.

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Table of Contents

        Conversion costs for 2009 decreased to $96.7 million from $131.8 million for 2008. The total dollars spent on conversion costs decreased year over year primarily as a result of significant cost reductions for natural gas, materials and supplies, outside services, and denaturant. Conversion cost per gallon decreased year over year to $0.49 per gallon in 2009 versus $0.70 per gallon in 2008. Our plants ran at 98% and 94% of capacity for 2009 and 2008, respectively, after adjusting for differences in denaturant blending levels.

        Depreciation for 2009 totaled $14.4 million, versus $14.5 million in 2008. Motor fuel taxes were $5.6 million in 2009 versus $17.6 million in 2008. The cost of motor fuel taxes are recovered through billings to customers.

        Freight/logistics costs in 2009 decreased to $44.9 million, or approximately $0.16 per gallon, from $175.3 million, or $0.19 per gallon in 2008. Freight/logistics cost per gallon is calculated by taking total freight/logistics costs incurred and dividing by the total ethanol gallons sold. Total freight/logistics costs also include costs to ship co-products.

        The average cost of inventory was $1.44 at the end of 2009 as compared to $1.54 at the end of 2008 reflecting the decline in the average ethanol prices in 2009 using our weighted average FIFO approach to valuing inventory. The economic impact of selling gallons that were previously held in inventory at the end of 2008 during 2009 was a decrease in gross margin of approximately $4.2 million.

        SG&A expenses were $26.7 million in 2009, a decrease of $8.7 million, or 24.6%, as compared to $35.4 million in 2008. The decrease in SG&A is primarily attributable to decreases in salaries ($2.8 million), salaried stock compensation ($3.5 million) and outside services ($1.6 million) partially offset by an increase of $0.9 million in bad debt expense.

        Financial results for 2009 were also positively impacted by the recognition $10.2 million in income from termination of marketing agreements.

        Interest income in 2009 was $11 thousand, versus $3.0 million in 2008. The decrease in interest income is due to a reduction in available funds to invest.

        Interest expense in 2009 was $14.7 million, as compared to $5.1 million in 2008. Interest expense in 2009 consists of $8.1 million on our $300 million aggregate principal amount of Old Notes, $2.5 million on borrowing on our secured revolving credit facility, $2.3 million for amortization of deferred financing fees, and $1.8 million on our debtor-in-possession debt facility. We ceased the accrual of interest on the Old Notes as of the bankruptcy petition date. Interest expense capitalization was suspended with the halting of the expansion projects at Mt. Vernon and Aurora West. Interest expense in 2008 was reduced by the capitalization of $26.4 million in interest expense on the expansion projects.

        Due to our purchase in October 2008 of the remaining 21.58% of our Nebraska subsidiary we did not already own, we have been recognizing 100% of the operating results of Nebraska Energy, L.L.C. in our consolidated financial statements during 2009.

        Other non-operating income for 2009 includes $1.2 million net realized and unrealized gains on derivative contracts compared to $17.1 million in 2008. We have significantly reduced our hedging activity since the first quarter with only $31 thousand of non-operating income recorded in the last three quarters of 2009.

        The Company's annual tax benefit rate for 2009 was 16.2% of pre-tax loss. The income tax benefit recorded in 2009 is net of a valuation allowance of $24 million. The valuation allowance recognized on our gross deferred tax assets reduced our deferred tax asset to the amount we believe is more likely than not to be realized. The valuation allowance includes $13.7 million of reserve against the income tax benefit related to the capital losses incurred mainly on auction rate securities as we do not expect to have sufficient capital gains to offset the $35.2 million capital loss.

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Table of Contents

Year Ended December 31, 2008, Compared with Year Ended December 31, 2007

        Total gallons sold in 2008 were 936.0 million gallons, versus 690.2 million gallons sold in 2007, an increase of 245.8 million gallons, or an increase of 35.6%. The increase/(decrease) in gallons by source was as follows:

 
  For the Year Ended December 31,  
 
  2008   2007   Increase/
(Decrease)
  % Increase/
(Decrease)
 
 
  (In thousands, except for percentages)
 

Equity production

    188,764     191,999     (3,235 )   (1.7 )%

Marketing alliance purchases

    505,254     395,001     110,253 )   27.9 %

Purchase/resale

    249,028     111,451     137,577 )   123.4 %

Decrease (increase) in inventory

    (7,060 )   (8,280 )   1,220     N.M.*  
                   

Total

    935,986     690,171     245,815     35.6 %
                   

*
Not meaningful

        Net sales for 2008 were significantly higher as compared to 2007, at $2.2 billion for 2008 versus $1.6 billion in 2007. Overall, an increase in gallons sold and a higher average sales price of ethanol was complemented by higher co-product revenue. Gallons sold in 2008 increased, reflecting a higher number of gallons marketed on behalf of marketing alliance partners and a higher number of gallons purchased from other producers, offset somewhat by lower equity production. In 2008, the volume of ethanol purchased from marketing alliance partners increased due to the addition of new or expanded alliance facilities, primarily in the second half of the year. The average gross selling price of ethanol in 2008 increased to $2.22 per gallon, from the $2.08 received in 2007.

        Co-product revenue for 2008 totaled $128.5 million, an increase of $29.2 million, or 29.4%, from the 2007 total of $99.3 million. Co-product revenue increased during 2008 versus 2007 principally from an increase in co-product pricing due to record high corn prices. In 2008 and 2007, we sold 1.1 million tons of co-products. Co-product revenues, as a percentage of corn costs, were 35.9% during 2008, versus 36.7% in 2007. Co-product returns, as a percentage of corn costs, decreased in 2008 as compared to 2007 as the co-product prices failed to keep pace with the increase in corn prices in 2008.

        Cost of goods sold for 2008 was $2.2 billion, a significant increase over the $1.5 billion in 2007. Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from our marketing alliance partners, the cost of purchasing ethanol and bio-diesel from other producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers.

        Purchased ethanol in 2008 totaled $1.5 billion, versus approximately $972.5 million in 2007. The increase in purchased ethanol resulted from an increase in the number of gallons of ethanol purchased from marketing alliance partners, as well as an increase in purchase/resale gallons purchased, along with an increase in the cost per gallon of ethanol purchased. In 2008, we purchased 754.3 million gallons of ethanol at an average cost of $2.04 per gallon as compared to 506.5 million gallons of ethanol at an average cost of $1.92 in 2007.

        Production costs included corn costs, conversion costs (defined as the cost of converting the corn into ethanol, and included production salaries, wages and stock compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs) and depreciation. Corn costs in 2008 totaled $358.4 million, or $5.02 per bushel, versus $270.4 million, or $3.76 per bushel in 2007. The increase in corn costs was due to record high corn prices in 2008.

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        Conversion costs for 2008 increased to $131.8 million from $117.0 million for 2007. The total dollars spent on conversion costs increased year over year principally as a result of the record prices for commodities including oil and related products. Conversion cost per gallon increased year over year to $0.70 per gallon in 2008 versus $0.61 per gallon in 2007. Our plants ran at 94% of capacity for both 2008 and 2007 after adjusting for differences in denaturant blending levels.

        Depreciation for 2008 totaled $14.5 million, versus $12.6 million in 2007. Motor fuel taxes were $17.6 million in 2008 versus $13.9 million in 2007. The cost of motor fuel taxes are recovered through billings to customers.

        Freight/logistics costs in 2008 increased to $175.3 million, or approximately $0.19 per gallon, from $120.2 million, or $0.17 per gallon in 2007. Freight/logistics cost per gallon is calculated by taking total freight/logistics costs incurred and dividing by the total ethanol gallons sold. Total freight/logistics costs also include costs to ship co-products. The increase in freight/logistics cost was principally the result of record high oil prices and the related surcharges, and from general freight increases associated with moving product along longer supply lines to emerging new markets in the southeastern U.S.

        The average cost of inventory was $1.54 at the end of 2008 as compared to $1.80 at the end of the 2007 reflecting the decline in the average ethanol prices in 2008 using our weighted average FIFO approach to valuing inventory. The economic impact of selling gallons that were previously held in inventory at the end of 2007 during 2008 was a decrease in gross margin of approximately $9.5 million.

        SG&A expenses were relatively flat at $35.4 million in 2008, as compared to $36.4 million in 2007.

        Financial results for 2008 were also negatively impacted by pre-tax charges of $31.6 million of loss on the sale of auction rate securities, $9.9 million for demobilization expenses related to the suspension of our expansion projects, $4.3 million for a loss on an investment in another ethanol producer, $1.6 million related to the impairment of the plant development costs for our Pekin III expansion and the establishment of tax related valuation allowances totaling $16.1 million.

        Interest income in 2008 was $3.0 million, versus $12.4 million in 2007. The decrease in interest income was principally due to a reduction in funds available to invest.

        Interest expense in 2008 was $5.1 million, as compared to $16.2 million in 2007. Interest expense in 2008 reflected $30 million of interest incurred on our $300 million aggregate principal amount of Old Notes and $1.5 million of interest on our secured revolving credit facility, net of $26.4 million of capitalized interest. In 2007, our Old Notes were only outstanding from March to December.

        The non-controlling interest for 2008 was a $1.2 million credit to income compared to $1.3 million charge to income for 2007. This increase reflected the reduced operating performance of our Nebraska subsidiary caused primarily by the year over year significant increase in corn costs. Due to our purchase in October 2008 of the remaining 21.58% we did not already own, we began recognizing 100% of the operating results of Nebraska Energy, L.L.C. in our consolidated financial statements.

        Other non-operating income for 2008 included $17.1 million net realized and unrealized gains on derivative contracts. This included the effect of marking to market these contracts at December 31, 2008. Net gains on corn derivatives totaling $18.4 million were offset by net losses on short gasoline forward contracts totaling $1.3 million. For 2007, we recognized $0.1 million of net realized and unrealized loss on derivative contracts. Net gains on corn derivatives totaling $8.6 million were offset by the net losses on short gasoline forward contracts totaling $8.7 million.

        The Company's annual tax rate for 2008 was 13.7% of pre-tax loss. The income tax benefit recorded in 2008 was net of a valuation allowance of $16.1 million. The valuation allowance recognized on our gross deferred tax assets reduced our deferred tax asset to the amount we believed was more likely than not to be realized. The valuation allowance included $12.3 million of reserve against the

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income tax benefit related to the losses incurred on auction rate securities as we did not expect to have sufficient capital gains to offset the $31.6 million capital loss.

Trends and Factors that May Affect Future Operating Results

Ethanol Pricing

        Ethanol prices continued to be at or near the spot cost to produce ethanol during the second quarter of 2009 and 2010, making the cash spot margins near break-even. As the supply of ethanol from plants which are currently under construction begins to make its way into the marketplace or plants that are currently shut-in begin to produce ethanol again, ethanol pricing may remain soft, and gross margins may remain near break-even.

        As of June 30, 2010, we had contracts for delivery of ethanol totaling 29.8 million gallons through May 2011 at spot prices (using various Platt, OPIS and AXXIS indices).

        For the third quarter of 2010, we have contracts for delivery of ethanol totaling 26.6 million gallon at spot prices (using various Platt, OPIS and AXXIS indices).

Corn

        Corn prices rose significantly from 2006 to 2008 and reached record levels during 2008. Since 2008, corn prices have declined with the economic conditions in general, along with most other commodities. We believe that this is due in part to lower than expected consumption, including for ethanol and for export as a result of concerns of global recession and reductions in global demand. However, we continue to believe that corn prices are likely to remain above historical levels for the foreseeable future.

        We continuously purchase corn for physical delivery from suppliers using forward purchase contracts in order to assure supply. As we do this, we have in the past often shorted a like amount of CBOT corn futures with similar dates to lock in the basis differential. We have also occasionally used CBOT futures contracts to lock in the price of corn by taking long positions in CBOT contracts in order to reduce our risk of price increases. Exchange traded forward contracts for commodities are marked to market each period. Our forward physical purchases of corn are not marked to market.

        At June 30, 2010, we had fixed the price of 4.7 million bushels of corn through January 2011 at an average cost of $3.49 per bushel, representing approximately 12.5% of our corn requirements for the remainder of 2010, excluding our expansion facilities under construction.

Supply and Demand

        According to the RFA, the annual ethanol production capacity in the U.S. of plants currently in operation and those under construction is almost 14.0 billion gallons annually. This volume of ethanol production exceeds the mandate for renewable biofuel consumption required in 2013 of 13.8 billion gallons. Ethanol produced in the U.S. competes with sugar-based ethanol produced in Brazil. This domestic production capacity, along with imports, may cause supply to exceed demand. If additional demand for ethanol is not created, either through additions to discretionary blending (through increased penetration rates in areas that blend ethanol today or through the establishment of new markets where little or no ethanol is blended today), or through additional state level mandates, the excess supply may cause ethanol gross margins to decrease, perhaps substantially.

Plant Shutdown

        On June 29, 2010, we temporarily shut down our dry mill plant in Aurora, Nebraska (NELLC) to make some mechanical improvements to the facility. The shutdown was extended during this period of depressed margins to accelerate a required power outage at both facilities to complete some necessary

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electrical work for the Aurora West facility which is currently under construction. We completed the work in early August 2010, and the plant became operational again on August 14, 2010.

Natural Gas Prices

        Natural gas is an important input in our ethanol and co-product production process. We use natural gas primarily to dry distillers grains for storage and transportation over longer distances. This allows us to market distillers grains to broader livestock markets in the U.S. Natural gas prices fluctuated significantly during 2009. Our current natural gas usage is approximately 283,000 MMBtu's per month.

Ethanol Supports

        We receive significant benefits from federal and state statutes, regulations and programs and the trend at the governmental level appears to be to continue to try to provide economic support to the ethanol industry. Notwithstanding the above, changes to federal and state statutes, regulations or programs could have an adverse effect on our business. Recent federal legislation, however, has been of benefit to the ethanol industry. In December 2007, the EISA was passed which contained a new increased RFS. The new RFS requires fuel refiners to use a certain minimum amount of renewable fuels (including ethanol) which will rise from 12.95 billion gallons in 2010 to 36 billion gallons by 2022. Ethanol benefits from an excise tax credit of $0.45 per ethanol gallon (prior to January 1, 2009, the excise tax credit was $0.51 per gallon). Barring enactment of new legislation, this tariff will expire on December 31, 2010 (legislation has been introduced in Congress to extend the VEETC at a reduced level, and action is expected on the proposal prior to the November mid-term elections; however, the final outcome remains unclear). This excise tax credit provides incentives for blenders and refiners to blend ethanol with gasoline.

Expansion

        We have resumed construction of our plants in Aurora and Mt. Vernon. We are contractually obligated to complete construction of the plants at Aurora and Mt. Vernon and may incur significant penalties if we fail to complete these facilities as previously scheduled. See "Risk Factors—We are contractually obligated to complete certain capacity expansions in Aurora, Nebraska and Mount Vernon, Indiana. If we fail to complete them in a timely manner we may be subject to material penalties."

Cancellation of indebtedness income ("COD")

        We recognized income from COD when we emerged from bankruptcy to the extent that debt is discharged for consideration to a creditor for an amount that is less than the amount of such debt. For these purposes consideration includes the amount of cash and the fair market value of property, including stock of the debtor, transferred to the creditor. The amount of COD income, in general, is the excess of (a) the adjusted issue price of the indebtedness satisfied, over (b) the sum of the amount of cash paid and the fair market value of any new consideration (including the new stock of the Company following emergence from bankruptcy) given in satisfaction of the cancelled debt. The amount of COD income we expect to realize is $52 million for U.S. federal income tax purposes.

        To the extent of COD income, we are required to reduce certain of our tax attributes (principally, the current year tax losses, capital loss carryforward and the tax basis in our assets) in the year following emergence. Among other things, this would have the effect of reducing our future depreciation deductions. The American Recovery and Reinvestment Act of 2009 provided an exception to the immediate realization of COD income, which would permit us to elect to defer the current recognition of any COD income, and instead recognize any such income ratably over a five-year period beginning in 2014. Currently, we cannot determine if we will make the deferral election for COD income, as described above.

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Section 382 limitations

        Section 382 of the Internal Revenue Code limits the ability of a company that undergoes an ownership change, which is generally any change in ownership of more than 50% of its stock over a three-year period, to utilize its net operating loss carryforwards and certain built-in losses (generally, the excess of the tax basis in an asset over its fair market value as of the Section 382 change date) following the ownership change. The built-in-loss rules apply to the depreciation of the excess tax basis, as well as losses on disposal. These rules generally operate by focusing on ownership changes among stockholders owning directly or indirectly 5% or more of the stock of a company and any change in ownership arising from a new issuance of stock by the company.

        No net operating loss carryforward exists for the 2009 tax year. The consummation of the Plan generated an "ownership change" as defined in Section 382, which limits our ability to utilize certain carryover tax attributes. Any net operating loss generated in the 2010 year prior to our emergence from bankruptcy, and our net unrealized built in losses may be limited by Section 382 which could potentially result in the significant acceleration of tax payments. Our state net operating loss carryforwards are also subject to similar, but varying, restrictions on their future use.

Liquidity and Capital Resources

Overview and Outlook

        The following table sets forth selected information concerning our financial condition:

 
   
  December 31,  
 
  June 30,
2010
 
 
  2009   2008  
 
  (Unaudited)
  (In thousands)
 

Cash and cash equivalents

  $ 50,177   $ 52,585   $ 23,339  

Net working capital

    57,443   $ 38,136   $ (294,039 )

Total debt(1)

    105,000   $ 42,765   $ 352,200  

Current ratio

    2.96     1.60     0.39  

(1)
As of December 31, 2009, total debt excludes our Old Notes which are recorded in pre-petition liabilities subject to compromise.

        As a result of the chapter 11 cases and the circumstances leading to the chapter 11 cases as described elsewhere in this prospectus, we faced uncertainty regarding the adequacy of our liquidity and capital resources and had limited access to financing. The bankruptcy filing constituted an event of default under our secured revolving credit facility and the indenture governing our Old Notes, and the debt obligations under those agreements became automatically and immediately due and payable, subject to the automatic stay provisions of Section 362 of the Bankruptcy Code. As of April 7, 2009, the amount of outstanding borrowings and letters of credit under the secured revolving credit facility totaled approximately $18.4 million and $22.0 million, respectively, and the aggregate principal amount outstanding on our Old Notes was $300 million.

        At emergence from bankruptcy on March 15, 2010, we obtained approximately $98 million of proceeds through the issuance of $105 million principal amount of our Notes and 1,710,000 shares of common stock. Upon emergence we used these proceeds to pay $27.8 million to retire our previous secured revolving credit facility, $15.0 million to retire our debtor-in-possession debt facility, $17.9 million to Kiewit Energy Company to repay secured claims related to our expansion projects at Aurora, Nebraska and Mt Vernon, Indiana and $4.9 million to pay other secured and priority claims. Our Old Notes of $300.0 million aggregate principal amount of indebtedness, along with $15.5 million of interest, were discharged upon emergence from bankruptcy.

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Sources of Liquidity

        Our principal sources of liquidity are cash and cash equivalents, cash provided by our borrowing facilities, and cash provided by operations.

        Cash and cash equivalents.    For the first six months of 2010, cash and cash equivalents decreased by $2.4 million. Cash and cash equivalents as of June 30, 2010 and December 31, 2009 were $50.2 million and $52.6 million, respectively.

        Cash available under our liquidity facility.    As described further below, pursuant to the plan of reorganization, on the effective date of our plan of reorganization, the Company and its subsidiaries, as borrowers, entered into the Revolving Credit Agreement with PNC, as lender and as agent, providing for a $20 million Revolving Facility. Amounts under the Revolving Facility may be borrowed, repaid and reborrowed with all amounts outstanding due and payable on March 15, 2013. The maximum amount outstanding under the Revolving Facility is limited by the amount of eligible receivables and eligible inventory of the borrowers. The Revolving Credit Agreement contains mandatory prepayment requirements in certain circumstances upon the sale of certain collateral, subject to the ability to reborrow revolving advances. Termination of the Revolving Facility is subject to a prepayment premium if terminated more than 90 days prior to the third anniversary of the Revolving Facility.

        Total liquidity at June 30, 2010 was $56.1 million, comprised of $50.2 million in cash and cash equivalents and $5.9 million availability under the Revolving Facility. As of June 30, 2010, there were no amounts drawn against the Revolving Facility, and no outstanding letters of credit issued under the Revolving Facility.

        Cash provided by operations.    Net cash used in operating activities in the first six months of 2010 was $22.5 million, as compared to cash provided by operating activities of $14.1 million for the first six months of 2009. Cash used by operations in 2010 was negatively impacted by significant operating losses incurred in the first half of 2010 and payments of secured and priority claims as we emerged from bankruptcy. In the first half of 2009, we offset an operating loss by generating significant amounts of cash from the liquidation of receivables and inventory, along with the receipt of alliance termination payments, offset partially by reductions in accounts payable. As a result of our bankruptcy filing, we did not pay pre-petition accounts payable as they came due, which provided cash from operations.

Uses of Liquidity

        Our principal uses of liquidity are payments related to our outstanding debt and liquidity facility, working capital, funding of operations, and capital expenditures.

        Payments related to our outstanding debt and liquidity facility.    During the first half of 2010, we used $42.8 million of cash to make required reductions in borrowings on our secured revolving credit facility with JPMorgan Chase and our debtor-in-possession debt facility. At June 30, 2010, the Company had $6.3 million in letters of credit outstanding as issued by our prior lenders. The $6.3 million outstanding letters of credit were collateralized by $7.8 million in a restricted cash account.

        Working capital.    Our net working capital position increased by $19.3 million during the first half of 2010.

        Capital expenditures.    During the first six months of 2010, we spent approximately $23.6 million on capital projects. Of this amount, $1.5 million was spent on maintenance and environmental projects, while $22.1 million (including capitalized interest) was spent on our capacity expansion projects. In April 2010, we resumed construction activity on the suspended capacity expansion projects in Mt. Vernon, Indiana and Aurora, Nebraska and we expect to incur capital expenditures of approximately $58.9 million related to completing those facilities (excluding capitalized interest). In

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addition, we made a $5.0 million non-refundable deposit on the Canton facility, which we acquired in August 2010. We expect to make capital expenditures of approximately $7.0 million during the remainder of 2010 on the facility. See "—Recent Events—Acquisition of Canton, Illinois Facility."

Debtor-In-Possession Financing

        On April 7, 2009, we entered into a debtor-in-possession term sheet with certain lenders for a $30.0 million debtor-in-possession debt facility. The debtor-in-possession term sheet provided for a first priority debtor-in-possession financing composed of a term loan facility made available to certain of our subsidiaries in a maximum aggregate principal amount of up to $30.0 million. Proceeds of the debtor-in-possession debt facility were to be used, among other things, to (i) fund our working capital and general corporate needs and the costs of the chapter 11 cases in accordance with an approved budget, and (ii) provide adequate protection, in accordance with the terms of the debtor-in-possession debt facility, to the pre-petition agent and pre-petition lenders under our existing credit facilities.

        On April 14, 2009, the Bankruptcy Court entered an interim order approving the debtor-in-possession debt facility and on May 5, 2009, entered an order approving the facility on a final basis.

        In accordance with the terms of the plan of reorganization, the balances owed on the debtor-in-possession debt facility were paid in full on the effective date of our plan of reorganization.

13% Senior Secured Notes due 2015

        Pursuant to the plan of reorganization and the Bankruptcy Court's February 24, 2010 confirmation order approving and confirming the plan of reorganization (the "Confirmation Order"), on the effective date of our plan of reorganization, the Company issued and sold an aggregate of $105.0 million principal amount of the Notes. In addition, on August 19, 2010, the Company issued and sold an additional $50.0 million in aggregate principal amount of Notes. The Notes were issued under an indenture (the "Indenture") dated as of March 15, 2010 among the Company, each of the Company's direct and indirect wholly-owned subsidiaries, as guarantors (the "Guarantors"), and Wilmington Trust FSB, as trustee and collateral agent, in private transactions that were not subject to the registration requirements of the Securities Act. The Notes accrue interest at a rate of 13% for cash interest payments and 15% if the Company elects paid-in-kind interest payments. The Company may elect, prior to each interest payment date, whether to make each interest payment on the Notes (i) entirely in cash or (ii) 8/15 in cash and 7/15 in paid-in-kind interest. The Notes are fully and unconditionally guaranteed by the Guarantors. The Company will pay interest on the Notes quarterly in arrears on March 15, June 15, September 15 and December 15 of each year, starting on June 15, 2010. The Notes mature on March 15, 2015.

        The Notes and the guarantees of the Guarantors are secured by a first-priority lien on substantially all of the Company's and the Guarantors' assets (other than the assets subject to the first-priority lien granted under the Revolving Credit Agreement) and by a second-priority lien on the Company's and the Guarantors' assets that are subject to the first-priority lien granted under the Revolving Credit Agreement.

        Subject to certain exceptions, the Indenture limits or restricts, among other things, the Company's (and, in certain cases, the Guarantors' or the Company's restricted subsidiaries') ability to (i) incur or assume additional debt or provide guarantees in respect of obligations of other persons; (ii) issue convertible stock and preferred stock, (iii) pay dividends or distributions or redeem or repurchase capital stock; (iii) prepay, redeem or repurchase debt; (iv) make loans and investments; (v) incur certain liens; (vi) impose limitations on dividends, loans or asset transfers from its subsidiaries; (vii) sell or otherwise dispose of assets, including capital stock of its subsidiaries; (viii) consolidate or merge with

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or into, or sell substantially all of its assets to, another person; (ix) enter into transactions with affiliates; and (x) impair the security interest in the collateral securing the Notes.

        If certain events related to a change of control of the Company occur, each holder of Notes will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess of $2,000) of that holder's Notes for an amount in cash equal to 101% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest on the Notes repurchased to the date of repurchase, pursuant to the terms set forth in the Indenture. The Indenture also requires the Company to offer to repurchase the Notes at 100% of the principal amount of the Notes repurchased plus accrued and unpaid interest on the Notes repurchased to the date of repurchase if the aggregate sum of proceeds received by the Company from certain assets sales and events of loss and not otherwise used by the Company in accordance with the terms of the Indenture exceeds $5 million.

        The Company may redeem the Notes in whole or in part prior to their maturity date for a premium to the outstanding principal amount, as provided in the Indenture. If we enter into the New Term Loan Facility, we intend to redeem the entire outstanding principal amount of the Notes at a redemption price of 105% of the principal amount, plus accrued and unpaid interest. See "—Debt Commitment Letter" below.

        The Indenture also provides for customary events of default, including, among others, the failure to make payments when due, noncompliance with covenants and the occurrence of certain bankruptcy proceedings. If an event of default occurs and is continuing, then the trustee or the holders of not less than 25% in aggregate principal amount of the outstanding Notes may declare the principal of, and any accrued interest on, the Notes to be due and payable immediately. In addition, upon the occurrence and during the continuance of an event of default or if the Company or the Guarantors do not comply with certain of their obligations under certain registration rights agreements entered into pursuant to the plan of reorganization, interest on the Notes will accrue at an additional 2% per annum.

        The Notes and the guarantees rank equally in right of payment with all of the Company's and the Guarantors' existing and future senior indebtedness, including indebtedness incurred under the Revolving Credit Agreement, and senior to all of the Company's and the Guarantors' existing and future subordinated indebtedness.

Secured Revolving Credit Facility

        Pursuant to the plan of reorganization, on March 15, 2010, the Company and its subsidiaries, as borrowers, entered into the Revolving Credit Agreement with PNC, as lender and as agent, providing for a $20.0 million Revolving Facility. Amounts under the Revolving Facility may be borrowed, repaid and reborrowed with all amounts outstanding due and payable on March 15, 2013. The maximum amount outstanding under the Revolving Facility is limited by the amount of eligible receivables and eligible inventory of the borrowers. The Revolving Credit Agreement contains mandatory prepayment requirements in certain circumstances upon the sale of certain collateral, subject to the ability to reborrow revolving advances. Termination of the Revolving Facility is subject to a prepayment premium if terminated more than 90 days prior to the third anniversary of the Revolving Facility.

        Amounts outstanding under the Revolving Facility bear interest at a floating rate equal to, at the option of the Company, the alternate base rate plus 3.00% or the Eurodollar rate plus 6.00%. The Company will pay a commitment fee of 1.00% per annum for unused committed amounts under the Revolving Facility. Interest is due monthly in arrears with respect to alternate base rate loans and at the end of each interest period with respect to Eurodollar rate loans. For Eurodollar rate loans with interest periods greater than 3 months, interest is payable every 3 months from the first day of such interest period and on the last day of such interest period.

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        Up to $17.0 million of the Revolving Facility may be applied to letters of credit. Issued letters of credit reduce availability under the Revolving Facility. The Company will pay a fee for issued and undrawn letters of credit at 6.00% per annum of the average daily face amount of each outstanding letter of credit and a per annum fronting fee of 0.25% payable quarterly.

        The Revolving Credit Agreement contains, and the Company and its subsidiaries will be required to comply with, customary covenants for facilities of this type, such as (i) affirmative covenants as to maintenance of existence, compliance with laws, preservation of collateral, environmental matters, insurance, payment of taxes, access to books and records, use of proceeds, maintenance of cash management systems, priority of liens in favor of the lenders, maintenance of assets and monthly, quarterly, annual and other reporting obligations, and (ii) negative covenants, including limitations on liens, additional indebtedness, loans, guarantees, dividends, nature of business, transactions with affiliates, investments, asset dispositions, capital expenditures, mergers and consolidations, formation of subsidiaries, accounting changes and amendments to constituent documents.

        The Revolving Credit Agreement includes customary events of default for facilities of this type, including (i) failure to pay principal, interest or other amounts when due, (ii) breach of representations and warranties, (iii) breach of covenants, (iv) bankruptcy, (v) occurrence of a material adverse effect, (vi) cross-default to other indebtedness, (vii) judgment default, (viii) invalidity of any loan document, (ix) failure of liens to be perfected, (x) the occurrence of a change of ownership, (xi) loss of material licenses or permits, cessation of operations and the incurrence of certain ERISA liabilities. Upon the occurrence and continuance of an event of default, the lenders may (i) terminate their commitments under the Revolving Facility, (ii) accelerate the repayment of all of the Company's obligations under the Revolving Facility, and (iii) foreclose on the collateral granted to them.

        The Revolving Credit Agreement grants a first priority lien (subject to certain exclusions) to PNC on the Company's and its subsidiaries' (i) accounts receivable, (ii) general intangibles, (iii) intellectual property, (iv) inventory, (v) investment property, (vi) instruments related to the foregoing, (vii) deposit accounts, (viii) letters of credit, (ix) money, (x) letter-of-credit rights, (xi) books and records, and (xii) all proceeds of the foregoing.

        On August 6, 2010, we and our subsidiaries, as borrowers, entered into the First Amendment with the financial institutions party thereto as lenders and PNC. The First Amendment amends the Revolving Credit Agreement by increasing the letter of credit sublimit under the Revolving Credit Agreement from $12.0 million to $17.0 million. The First Amendment also modifies the capital expenditure limitations applicable to us and our subsidiaries under the Revolving Credit Agreement and our daily inventory reporting requirements to permit PNC to agree not to require daily reporting by the borrowers of in-transit inventory.

Warrant Agreement

        Pursuant to the plan of reorganization and Confirmation Order, on March 15, 2010, the Company entered into a warrant agreement (the "Warrant Agreement") with American Stock Transfer & Trust Company, LLC, as warrant agent (the "Warrant Agent"). Pursuant to the Warrant Agreement, the Company issued warrants to purchase an aggregate of 450,000 shares of common stock, par value $0.001 per share, of the Company, subject to adjustment for, among other things, the matters described below (the "Warrants"). The Warrants will expire on March 15, 2015 or, if earlier, in connection with the consummation of a change of control of the Company (the "Expiration Date"); provided that the Company may accelerate the Expiration Date in certain circumstances as set forth in the Warrant Agreement.

        Each Warrant entitles its holder to purchase one share of common stock at an exercise price of $40.94 (the "Exercise Price"), subject to adjustment for, among other things, the matters described below. Except as otherwise set forth in the Warrant Agreement, Warrants may be exercised at any time

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after issuance until the Expiration Date. Holders that elect to exercise the Warrants must do so by (i) providing written notice of such election to the Warrant Agent prior to the Expiration Date, in the form prescribed in the Warrant Agreement, (ii) surrendering to the Warrant Agent the certificate evidencing such Warrants and (iii) (x) paying the applicable exercise price for all Warrants being exercised or (y) if a change of control or similar transaction occurs where the Warrants would become exercisable for cash, in lieu of paying the Exercise Price, notify the Warrant Agent that such holder elects to receive a cash payment equal to the net amount payable in such transaction with respect to the number of shares such Warrants are being exercised for in excess of the Exercise Price for all such Warrants.

        Holders of the Warrants (solely in their capacity as a holder of Warrants) are not entitled to any rights as a stockholder of the Company, including, without limitation, the right to vote, receive notice of any meeting of stockholders or receive dividends, allotments or other distributions. The number of shares of common stock for which a Warrant is exercisable and the Exercise Price are subject to adjustment from time to time upon the occurrence of certain customary adjustment events.

        In addition, upon the occurrence of certain events constituting a merger of the Company into or a consolidation of the Company with another entity, or a sale of all or substantially all of the Company's assets, or a merger of another entity into the Company, or similar event, each holder of a Warrant will have the right to receive, upon exercise of a Warrant (if then exercisable), an amount of securities, cash or other property receivable by a holder of the number of shares of common stock for which a Warrant is exercisable immediately prior to such event.

Debt Commitment Letter

        On August 2, 2010, we entered into the Debt Commitment Letter with Citi under which Citi has agreed, at a subsequent time, to use its best efforts to arrange a syndicate of lenders that will provide us with the New Term Loan Facility, and to act as lead arranger, bookrunner, administrative agent and collateral agent for the New Term Loan Facility, on the terms and subject to the conditions set forth in the Debt Commitment Letter. Consummation of the debt financing is subject to various conditions set forth in the Debt Commitment Letter, including the absence of certain "material adverse effects" with respect to us and our subsidiaries, taken as a whole.

        The New Term Loan Facility will mature on the fifth anniversary of the closing date of the New Term Loan Facility. The New Term Loan Facility will require us to maintain a specified minimum liquidity and a specified maximum debt to capitalization ratio. Additionally, the New Term Loan Facility will contain other customary affirmative and negative covenants concerning the conduct of our business operations. The New Term Loan Facility will also contain customary events of default. Upon the occurrence of an event of default, our obligations under the New Term Loan Facility may be accelerated and all indebtedness thereunder would become immediately due and payable.

        In connection with the New Term Loan Facility, we intend to redeem the entire outstanding principal amount of the Notes at a redemption price of 105% of the principal amount, plus accrued and unpaid interest. However, we are under no obligation to enter into any such debt financing and cannot assure you that we will enter into any such financing transaction on terms acceptable to us, if at all.

Off-Balance Sheet Arrangements

        We have not entered into any off-balance sheet arrangements that either have, or are reasonably likely to have, a material adverse current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

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Contractual Obligations and Commercial Commitments

        The following table provides a summary of our contractual obligations and commercial commitments as of December 31, 2009. Former obligations of the Company for contracts rejected in bankruptcy are excluded from the table below. Other non-current liabilities included in our consolidated balance sheet that may not be fully disclosed below include accrued pension and post retirement costs. Refer to Notes 15 and 17 of our 2009 annual financial statements and Notes 9 and 16 of our second quarter of 2010 quarterly financial statements.

 
  Payments due or expiring by period  
 
  Total   1 year   1 - 3 years   3 - 5 years   More than
5 years
 
 
  (In millions)
 

Contractual obligations:

                               
 

Railcar leases

  $ 2.1   $ 1.0   $ 0.7   $ 0.2   $ 0.2  
 

Terminal leases

    3.3     0.4     0.8     0.6     1.5  
 

Ports of Indiana wharfage

    4.6     0.3     0.5     0.6     3.2  
 

Headquarters building lease

    1.2     0.3     0.3     0.3     0.3  
 

Headquarters furniture and equipment lease

    0.3     0.3              
 

Mt. Vernon Lease

    6.2     0.4     0.7     0.7     4.4  
 

IT Services and Licenses

    1.4     0.4     0.9     0.1      
 

Coal Contracts

    11.4     11.4              
 

Natural Gas

    18.7     1.8     1.8     1.9     13.2  
 

Denaturant

    0.5     0.5              
 

Corn

    5.5     5.5              
 

Commitments for Capital Expenditures

    0.4     0.4              
 

Master Development Agreement(1)

    4.2     1.7     2.5          
                       

Total Contractual obligations

  $ 59.8   $ 24.4   $ 8.2   $ 4.4   $ 22.8  
                       

(1)
If the Aurora West facility is completed prior to July 2012, this commitment will be reduced.

Environmental Matters

        We are subject to extensive federal, state and local environmental, health and safety laws, regulations and permit conditions (and interpretations thereof), including, among other things, those relating to the discharge of hazardous and other waste materials into the air, water and ground, the generation, storage, handling, use, transportation and/or disposal of hazardous materials, and the health and safety of our employees. Compliance with these laws, regulations, and permits require us to incur significant capital and other costs, including costs to obtain and maintain expensive pollution control equipment. They may also require us to make operational changes to limit actual or potential impacts to the environment. A violation of these laws, regulations or permit conditions can result in substantial administrative and civil fines and penalties, criminal sanctions, imposition of clean-up and site restoration costs and liens, suspension or revocation of necessary permits, licenses and authorizations and/or the issuance of orders enjoining or limiting our current or future operations. In addition, environmental laws and regulations (and interpretations thereof) change over time, and any such changes, more vigorous enforcement policies or the discovery of currently unknown conditions may require substantial additional environmental expenditures.

        We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged for the disposal of hazardous wastes. For instance, over ten years ago soil and groundwater contamination from fuel oil contamination at a storage site was identified at our Illinois campus. The

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fuel oil tanks were removed and a portion of the area has been capped, but no remediation has been performed. If any of these sites are subject to investigation and/or remediation requirements, we may incur strict and/or joint and several liability under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws which impose strict liability for all or part of the costs of such investigation, remediation, or removal costs and for damages to natural resources whether the contamination resulted from the conduct of other or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties or other impacts of our operations. While costs to address contamination or related third-party claims could be significant, based upon currently available information, we are not aware of any material liability relating to contamination or such third party claims. We have not accrued any amounts for environmental matters as of June 30, 2010. The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

        In addition, the hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, abnormal pressures and spills) may result in releases of hazardous substances and other waste materials, and may result in claims from governmental authorities or third parties relating to actual or alleged personal injury, property damage, or damages to natural resources. We maintain insurance coverage against some, but not all, potential losses associated with our operations. Our coverage includes, but is not limited to, physical damage to assets, employer's liability, comprehensive general liability, automobile liability and workers' compensation. We do not carry environmental insurance. We believe that our insurance is adequate for our industry, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of events which result in significant personal injury or damage to our property, natural resources or third parties that is not covered by insurance could have a material adverse impact on our results of operations and financial condition.

        Our air emissions are subject to the federal Clean Air Act, as amended, and similar state laws which generally require us to obtain and maintain air emission permits for our ongoing operations, as well as pre-approval for any expansion or construction of existing facilities or new facilities or modification of certain projects or facilities. Obtaining and maintaining those permits requires us to incur costs, and any future more stringent standards may result in increased costs and may limit or interfere with our operations. In addition, the permits ultimately issued may impose conditions which are more costly to implement than we had anticipated. These costs could have a material adverse effect on our financial condition and results of operations. Because other ethanol manufacturers in the U.S. are and will continue to be subject to similar laws and restrictions, we do not currently believe that our costs to comply with current or future environmental laws and regulations will adversely affect our competitive position among domestic producers. However, because ethanol is produced and traded internationally, these costs could adversely affect us in our efforts to compete with foreign producers not subject to such stringent requirements. Our failure to comply with air emissions laws and regulations could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.

        Federal and state environmental authorities have been investigating alleged excess VOC emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities. The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility. If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar matter at our Nebraska facility due to the larger size of the Illinois wet mill facility. As of yet we have not established reserves for possible costs we may incur in connection with this investigation. In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.

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        We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the NESHAP for industrial, commercial and institutional boilers and process heaters. This NESHAP was issued in 2004 but subsequently vacated in 2007. The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers. The EPA is currently rewriting the NESHAP, which is expected to be more stringent than the vacated version. In the absence of a final NESHAP for industrial, commercial and institutional boilers and process heaters, we are working with state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed. We currently cannot estimate the amount that will be needed to comply with any future federal or state technology requirement regarding air emissions from our boilers.

        We currently generate revenue from the sale of carbon dioxide, a greenhouse gas, which is a co-product of the ethanol production process at each of our Illinois and Nebraska facilities. National greenhouse gas legislation is in the early stages of development in the U.S., and we are currently unable to determine the impact of potential greenhouse gas reduction requirements. Mandatory greenhouse gas emissions reductions may impose increased costs on our business and could adversely impact our operations, including our ability to continue generating revenue from carbon dioxide sales.

        On February 3, 2010 the EPA announced final revisions to the National RFS program (commonly known as the RFS program or RFS-2). This Rule makes changes to the RFS program as required by the EISA. The revised statutory requirements establish new specific annual volume standards for cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel that must be used in transportation fuel. The revised statutory requirements also include new definitions and criteria for both renewable fuels and the feedstock used to produce them, including new greenhouse gas emission thresholds as determined by lifecycle analysis. The regulatory requirements for RFS-2 will apply to domestic and foreign producers and importers of renewable fuel used in the U.S.

        This final action is intended to lay the foundation for achieving significant reductions of greenhouse gas emissions from the use and creation of renewable fuels, reductions of imported petroleum and further development and expansion of our nation's renewable fuels sector.

        On May 10, 2010, the EPA published a Direct Final Rule to "amend certain of the RFS program regulations" to correct "some technical errors and areas within the final RFS-2 regulations that could benefit from clarification or modification." As part of this Direct Final Rule, the EPA revised the RFS-2 "to require that construction of grandfathered renewable fuel production facility for which construction commenced prior to December 19, 2007, be completed by December 19, 2010, rather than 36 months from the date of commencement of construction." The Direct Final Rule is effective as of July 1, 2010, except for sections upon which the EPA received adverse comment or request for a hearing. We are unaware of adverse comment or request for a hearing on the construction deadlines described above.

        RFS-2 sets the 2010 RFS volume standard at 12.95 billion gallons (bg). Further, for the first time, the EPA is setting volume standards for specific categories of renewable fuels including cellulosic, biomass-based diesel, and total advanced renewable fuels. For 2010, the cellulosic standard is set at 6.5 million gallons (mg); and the biomass based diesel standard is set at 1.15 bg (combining the 2009 and 2010 standards as proposed).

        In order to qualify for these new volume categories, fuels must demonstrate that they meet certain minimum greenhouse gas reduction standards, based on a lifecycle assessment, in comparison to the petroleum fuels they displace. Generally, ethanol plants either must meet the 20% reduction test or are grandfathered under special provisions. For plants under construction on which construction commenced prior to December 19, 2007 (including our Mt. Vernon and Aurora West plants under

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construction) the plants must be completed within 36 months in order to meet the requirements to be grandfathered or comply with the greenhouse gas reduction standards which require the use of Advanced Technologies defined by the regulations.

        See Note 19 of our 2009 annual financial statements for more information on our environmental commitments and contingencies.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        None.

Quantitative and Qualitative Disclosures about Market Risk

        We are exposed to various market risks, including changes in commodity prices. Market risk is the potential loss arising from adverse changes in market rates and prices. In the ordinary course of business, we may enter into various types of transactions involving financial instruments to manage and reduce the impact of changes in commodity prices, including price risk on anticipated purchases of corn, natural gas and the sale of ethanol. We do not enter into derivatives or other financial instruments for trading or speculative purposes.

Commodity Price Risks

        We are subject to market risk with respect to the price and availability of corn, the principal raw material we use to produce ethanol and ethanol by-products. In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions. This is especially true when market conditions do not allow us to pass along increased corn costs to our customers. The availability and price of corn is subject to wide fluctuations due to unpredictable factors such as weather conditions, farmer planting decisions, governmental policies with respect to agriculture and international trade, and global demand and supply. Our weighted-average gross corn costs for the six months ended June 30, 2010 and 2009 were $3.60 and $4.17 per bushel, respectively, and for the years ended December 31, 2009 and 2008 were $3.87 and $5.02 per bushel, respectively.

        We have firm-price purchase commitments with some of our corn suppliers under which we agree to buy corn at a price set in advance of the actual delivery of that corn to us. Under these arrangements, we assume the risk of a decrease in the market price of corn between the time this price is fixed and the time the corn is delivered. At June 30, 2010, we had commitments to purchase approximately 4.7 million bushels of corn through January 2011 at an average price of $3.49 per bushel from these corn suppliers. At December 31, 2009, we had firm-price purchase commitments to purchase 1.4 million bushels of corn at an average fixed price of $3.95 per bushel for delivery through December 2010. We have elected to account for these transactions as normal purchases under ASC 815, and accordingly, have not marked these transactions to market.

        In order to reduce our market exposure to price decreases, we have in the past, at the time we enter into a firm-price purchase commitment, entered into commodity futures contracts to sell a certain amount of corn at the then-current price for delivery to the counterparty at a later date. However, at June 30, 2010 and December 31, 2009, we were not party to any commodity futures contracts to hedge our risk with respect to corn price decreases. When we have these types of commodity futures contracts, we account for them under ASC 815. These futures contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative contracts, if any, is recognized in other current assets in the consolidated balance sheet, net of any cash paid to brokers.

        We have also, in the past, entered into commodity futures contracts in connection with the purchase of corn to reduce our risk of future price increases. We accounted for these transactions

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under ASC 815. These futures contracts were not designated as hedges and, therefore, were marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative contracts would be recognized in other current assets in the consolidated balance sheet, net of any cash received from the brokers. At June 30, 2010 and December 31, 2009, we were not party to any such commodity futures contracts to reduce our risk of future corn price increases.

        We are also subject to market risk with respect to ethanol pricing. Our ethanol sales are priced using contracts that can either be based upon a fixed price; based upon the price of wholesale gasoline plus or minus a fixed amount; or based upon a market price at the time of shipment. We sometimes fix the price at which we sell ethanol using fixed price physical delivery contracts. At June 30, 2010 and December 31, 2009, we had no fixed-price contracts to sell ethanol. These normal sale transactions would not be marked to market.

        From time to time, we also sell forward ethanol using contracts where the price is determined at a point in the future based upon an index plus or minus a fixed amount. At June 30, 2010 and December 31, 2009, we had not sold forward any ethanol using wholesale gasoline as an index plus a fixed spread. When we have these arrangements, we assume the risk of a price decrease in the market price of gasoline. In order to reduce our market exposure to price decreases, at the time we enter into a firm sales commitment, we may also enter into commodity forward contracts to sell a like amount of gasoline at the then-current price for delivery to the counterparty at a later date. We account for these transactions under ASC 815. These forward contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative liabilities is recognized in other current liabilities in the condensed consolidated balance sheets, net of any cash paid to brokers. We did not have any of this type of derivative position at June 30, 2010.

        We may also be subject to market risk with respect to our supply of natural gas which is consumed during the production of ethanol and its co-products and has historically been subject to volatile market conditions. Natural gas prices and availability are affected by weather conditions, overall economic conditions and foreign and domestic governmental regulation. The price fluctuation in natural gas prices over the 10 year period from January 1, 2000 through June 30, 2010, based on the New York Mercantile Exchange daily futures data, has ranged from a low of $1.83 per MMBtu in September 2001 to a high of $15.82 per MMBtu in 2005. Natural gas costs comprised 18.1%, 20.7%, 17.9% and 24.2%, respectively, of our total conversion costs for the six months ended June 30, 2010 and 2009 and the years ended December 31, 2009 and 2008, respectively.

        At June 30, 2010, we did not have any commitments to purchase natural gas in advance at prices other than at market. At December 31, 2009, we had purchased forward 134,700 MMBtu's of natural gas at an average fixed price of $6.19 per MMBtu through the first quarter of 2010. We have elected to account for these transactions as normal purchases under ASC 815 and accordingly, have not marked these transactions to market.

Material Limitations

        The disclosures with respect to the above noted risks do not take into account the underlying commitments or anticipated transactions. If the underlying items were included in the analysis, the gains or losses on the futures contracts may be offset. Actual results will be determined by a number of factors that are not generally under our control and could vary significantly from those results disclosed.

        We are exposed to credit losses in the event of nonperformance by counterparties on the above instruments, as well as credit or performance risk with respect to our hedged commitments. Although nonperformance is possible, we do not anticipate nonperformance by any of these parties.

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BUSINESS

Business Overview

        We are a producer and marketer of corn-based fuel-grade ethanol in the U.S. We market and distribute ethanol to many of the leading energy and trading companies in the U.S. We produced 197.5 million gallons and 188.8 million gallons of ethanol in 2009 and 2008, respectively. We derive our revenue primarily from the sale of ethanol. We also derive revenue from the sale of co-products (corn gluten feed and meal, corn germ, CCDS, carbon dioxide, DDGS and WDGS) and bio-products (brewers' yeast) which are produced as by-products during the production of ethanol at our plants and which generate revenue and allow us to help offset a significant portion of our corn costs. Historically, we have also been a large marketer of ethanol, distributing ethanol purchased from other third-party producers in addition to our own ethanol production. In 2009 and 2008, we distributed 66.4 million gallons and 754.3 million gallons, respectively, of ethanol produced by others. The decrease in distributed gallons from third party producers is attributable to the termination of our marketing alliance and substantial reduction in our purchase/resale supply operations in late 2008 and the first quarter of 2009. Historically, we have sourced ethanol from the following three sources:

    Ethanol we manufactured at our own plants, which we refer to as equity production;

    Ethanol we were obligated to purchase from a third party producer under contract where we shared costs and collected commissions, which we refer to as marketing alliance production; and

    Ethanol we purchased either on the spot market or under contract, which we refer to as purchase/resale.

        We market and sell ethanol without regard to the source of origination. With our own equity production combined with ethanol sourced from third parties (or non-equity production), we marketed and distributed 277.5 million, 936.0 million and 690.2 million gallons of ethanol for the years 2009, 2008 and 2007, respectively. Because of the challenges facing the ethanol industry in general and us in particular, we sharply decreased the number of gallons of ethanol we sold that were produced by others in 2009 by terminating our marketing alliance and significantly reducing our purchase/resale operation.

Organization

        We are a Delaware corporation organized in 2003 in connection with the acquisition of our business by the Morgan Stanley Capital Partners funds ("MSCP funds"). We and our predecessors have been engaged in the production and marketing of ethanol since 1981. Our principal executive offices are located at 120 North Parkway Drive, Pekin, Illinois 61554.

Equity Ethanol Production

        We own and operate one of the few coal-fired, corn wet mill plants in the U.S. in Pekin, Illinois, which we refer to as the "Illinois wet mill facility." In addition, we own and operate a natural gas-fired corn dry mill plant in Pekin, Illinois which we refer to as the "Illinois dry mill facility," and a natural gas-fired corn dry mill plant in Aurora, Nebraska, which we refer to as the "Nebraska facility." We refer to our Illinois dry mill and wet mill facilities collectively as our "Illinois facilities." Further, in August 2010 we acquired a 38 million gallon undenatured annualized capacity ethanol production facility in Canton, Illinois, which we refer to as the "Canton facility."

        The denaturant we use is typically a low-grade gasoline. Beginning in 2009, IRS regulations reduced the maximum permitted amount of denaturant for which the VEETC can be taken to 1.96%. In November 2008, our Illinois dry mill facility received a revised permit from the Illinois Environmental Protection Agency allowing production capacity at that facility to increase to 63.3 million gallons of undenatured ethanol. We have not increased the stated capacity of our Pekin dry mill to reflect the revised permit.

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        Our Illinois dry mill facility was completed in early 2007. The addition of this facility increased our total annual production capacity by approximately 57 million gallons. For each of the years ended December 31, 2009, 2008, and 2007, our facilities had a combined total ethanol production capacity of approximately 200 million gallons annually with corn processing capacity of approximately 77 million bushels per year at capacity. Our plants may operate at a capacity which is less than the stated capacity. We occasionally experience plant outages (both planned and unplanned), as well as other related productivity issues. Planned outages are typically for maintenance and average approximately one week per plant each year. We may also occasionally experience unplanned outages at our facilities which may negatively impact production and related revenue. Our plants ran at 98% of capacity for 2009 and at 94% of capacity for both 2008 and 2007 after adjusting for differences in denaturant blending levels.

        For the years ended December 31, 2009, 2008 and 2007, we produced 197.5 million, 188.8 million, and 192.0 million gallons of ethanol, respectively, from our own facilities. Our equity production operations generate the substantial majority of our operating income or loss.

By-Products

        We generate additional revenue through the sale of by-products (both co-products and bio-products) that result from the ethanol production process. These by-products include brewers' yeast, corn gluten feed and meal, corn germ, CCDS, carbon dioxide, DDGS and WDGS. The volume of by-products we produce varies with the level of our equity production. Scheduled maintenance, along with other non-scheduled operational difficulties, may affect the volume of by-products produced. We may also shift the mix of these by-products, to increase our revenue. By-product revenue is driven by both the quantity of by-products produced and the market price received for our by-products which have historically tracked the price of corn.

        For the years ended December 31, 2009, 2008 and 2007, we generated approximately $97.9 million, $128.5 million and $99.3 million, respectively, of revenue from the sale of co-products and bio-products, allowing us to recapture approximately 34.1%, 35.9% and 36.7% of our corn costs, respectively, in each of these years. Co-product returns, as a percentage of corn costs, decreased in 2009 as co-product pricing decreased more than corn costs. Co-products produced by the dry mill process have less value historically than those produced by the wet mill process. As a result of the addition of the Pekin dry mill, our overall product mix between wet and dry co-products produced changed from 67% higher value wet mill products and 33% lower value dry mill products prior to 2007, to roughly 50% higher value wet mill products and 50% lower value dry mill products beginning in 2007.

        Due to recent and planned industry increases in U.S. dry mill ethanol production, the production of co-products from dry mills in the U.S. has increased dramatically, and this trend may continue. This may cause co-product prices to fall in the U.S., unless demand increases or other market sources are found. To date, demand for DDGS (the principal co-product produced by dry mills) in the U.S. has increased roughly in proportion to supply. We believe this is because U.S. farmers use DDGS as a feedstock, and DDGS are slightly less expensive than corn, for which it is a substitute. However, if prices for DDGS in the U.S. fall, it may have an adverse effect on our business, which might be material.

Purchase/Resale

        Historically, we have also purchased ethanol from unaffiliated third-party producers and marketers on both a spot basis and under contract. These transactions were driven by our ability to purchase ethanol and then, through our distribution network and customer relationships, resell the ethanol. The margin from purchase/resale transactions could be volatile and we occasionally incurred losses on these transactions.

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        For the years ended December 31, 2008 and 2007, we purchased for resale 249.0 million and 111.5 million gallons of ethanol, respectively, from unaffiliated producers and marketers. As discussed below under "Marketing Alliance Production" and further discussed under "—Marketing Alliances," we began a program to rationalize our distribution network and reduce our sourcing of ethanol from third parties in late 2008. Our purchase/resale program was part of this rationalization process. Accordingly, we only purchased 35.5 million gallons of ethanol for resale from unaffiliated producers and marketers during 2009.

Marketing Alliance Production

        Historically, our marketing business was an important component of our business. Marketing alliance partners were third-party producers (including producers in which we may have had a non-controlling interest), who sold their ethanol production to us on an exclusive basis. Ethanol produced by our marketing alliance partners enabled us to meet major ethanol consumer needs by providing us with a nationwide marketing presence without having to make capital investments and through leveraging our marketing expertise and our distribution systems. Marketing alliance contracts required us to purchase all of the production from these facilities and sell it at contract or prevailing market prices. We were entitled to commissions on the sale of marketing alliance gallons in accordance with the terms of the marketing alliance contracts. The contribution to our operating income from the sale of marketing alliance gallons was relatively small as commission rates typically were 1% or less of the "netback" price. The netback price was the selling price of ethanol less a "cost recovery component." The cost recovery component represented reimbursement to us for certain costs, including freight, storage, inventory carrying cost and indirect marketing costs. The purchase price we paid our marketing alliance partners was based on an average price at which we sold ethanol less the cost recovery component and commission. Revenue from marketing alliance gallons sold included the gross revenue from such sales and not merely the commissions earned because we (i) took title to the inventory, (ii) were the primary obligor in the sales arrangement with the customer, and (iii) assumed all the credit risk.

        For the years ended December 31, 2008 and 2007, we purchased 505.3 million and 395.0 million gallons of ethanol, respectively, from our marketing alliance partners. However, with severely declining margins and general liquidity stress due to frozen credit markets, this model no longer worked for our alliance partners or the Company. As such, beginning in the fourth quarter of 2008, we negotiated termination agreements with our marketing alliance partners and began to rationalize our distribution network to primarily focus on sales of our equity production. For the year ended December 31, 2009, we purchased only 30.9 million gallons of ethanol from marketing alliance partners. We also recognized $10.2 million of income from the termination of our marketing alliance agreements in 2009.

Competitive Strengths

        We believe that our competitive strengths include the following:

    Strong Market Position.  We are a leading producer and marketer of ethanol in the U.S. based on both gallons of ethanol produced and sold. For the year ended December 31, 2009, we produced 197.5 million gallons, sold 66.4 million gallons of ethanol from non equity production, and reduced our ethanol inventory by 13.6 million gallons for a total sales volume of 277.5 million gallons.

    Diversified Supply Base.  Our facilities are diversified across geography, fuel source and technology, allowing us to capitalize on multiple opportunities and limit our exposure to any one input. We also generate revenue from multiple sources—equity (or produced), non-equity (or marketed but not produced) and co-products (or from our production).

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    Supplier of Choice.  We maintain long-standing customer relationships with most of the major integrated oil refiners operating in North America (including Royal Dutch Shell and its affiliates, Conoco Phillips Company, Valero Marketing and Supply Company and Chevron Corporation) due to our ability to distribute ethanol extensively.

    Low Cost Producer.  We believe we are one of the lowest cost producers of ethanol in the U.S. Our Illinois wet mill facility generates 38.0% of its own electricity and its remaining energy needs are met by using lower cost coal, which provides us significant cost savings compared to ethanol facilities that use higher cost natural gas to generate power. In addition, our Illinois wet mill facility, through its wet mill production process, generates higher margin co-products and bio-products, which allowed us to recapture 42.7% of our corn cost in the year ended December 31, 2009, which is a higher percentage than our competitors who employ the dry mill production process. At our Illinois dry mill facility and our Nebraska facility which employs the dry mill process, we recaptured 26.7% and 24.5% of our total corn costs, respectively, in the year ended December 31, 2009.

    Experienced and Proven Management Team.  Our management team has a combined 64 years of experience in the ethanol production industry. Our Chief Executive Officer, Thomas Manuel, was previously the President and Chief Executive Officer of ASAlliances Biofuels LLC and has 40 years experience in managing commodity-related businesses. John Castle, our Chief Financial Officer, was previously the Senior Vice President of Operations and Chief Financial Officer of White Energy, Inc. an ethanol production company.

Business and Growth Strategy

        We are pursuing the following business and growth strategies:

    Add Production Capacity to Meet Expected Demand for Ethanol.  We have identified opportunities to increase our equity production capacity through the development of new production facilities and are continually exploring acquisition opportunities. We are currently building 110 million gallon undenatured annualized capacity ethanol production facilities at both Mt. Vernon, Indiana and Aurora, Nebraska, which we expect to complete in the fourth quarter of 2010, and in August 2010 we acquired the Canton facility, which we expect to become operational in the second quarter of 2011. After giving effect to the completion of these projects, our expected ethanol production capacity will be approximately 460 million gallons per year.

    Capitalize on Current and Changing Regulation.  Through continued investment in increasing production capacity, we believe we are well positioned to take advantage of the current and changing regulatory environment in our industry. For example, the EISA increased the mandated minimum use of renewable fuels to 9 billion gallons in 2008 (up from a 5.4 billion gallon requirement, which was the previous mandated 2008 requirement under the Energy Policy Act of 2005). The mandated usage of renewable fuels increases to 36 billion gallons in 2022. The upper mandate for corn based ethanol is 15 billion gallons by 2015.

    Entry into new and diversified markets.  We are continually negotiating additional sales agreements. We persistently strive to enhance and optimize our multiple modes of transportation and sources of production. In addition, as numerous countries in Europe, Asia and South America have increased the mandated use of renewable fuels, we believe that there are burgeoning export opportunities for our ethanol and by products.

    Transform from Ethanol Seller to Risk Manager.  We apply risk mitigation and management techniques used for decades by well-established agricultural processing businesses such as ConAgra Foods, Cargill and Archer Daniels Midland. Combined with the termination of our marketing alliance and reduction in purchase/resale supply operations in late 2008 and the first

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      quarter of 2009, we now focus primarily on the production of ethanol using established, proven logistics management techniques rather than ethanol sales.

Industry Overview

        Ethanol is marketed across the U.S. as a gasoline blend component that serves as a clean air additive, an octane enhancer and a renewable fuel resource. It is blended with gasoline (i) as an oxygenate to help meet fuel emission standards, (ii) to improve gasoline performance by increasing octane levels and (iii) to extend fuel supplies. A small but growing amount of ethanol is also used as E85, a renewable fuels-driven blend comprised of up to 85% ethanol.

        Ethanol is generally sold through short-term contracts. Although ethanol has in the past generally been priced at either a negotiated fixed price or a price based upon the price of wholesale gasoline plus or minus a fixed amount, the majority of ethanol sold in the U.S. today is based upon a spot index price at the time of shipment. The price of ethanol has historically moved in relation to the price of wholesale gasoline and the value of the VEETC. However, the price of ethanol over the last three years has been largely driven by supply/demand fundamentals and the price of corn.

        According to recent industry reports, approximately 99.4% of domestic ethanol is produced from corn fermentation as of December 31, 2009 and is primarily produced in the Midwestern corn-growing states. The principal factor affecting the cost to produce ethanol is the price of corn.

        The U.S. fuel ethanol industry has experienced rapid growth, increasing from 1.4 billion gallons of production in 1998 to approximately 10.8 billion gallons produced in 2009, the latest year for which production information is available. The RFA reports that the U.S. fuel ethanol industry has 187 operating plants and approximately 13.0 billion gallons of annual production capacity (including idled capacity) as of January 2010.

        The demand for ethanol has been driven by recent trends as more fully described below:

    Mandated usage of renewable fuels.  The growth in ethanol usage has been supported by regulatory requirements dictating the use of renewable fuels, including ethanol. The EISA signed into law on December 19, 2007, requires mandated minimum usage of renewable fuels of 12.95 billion gallons in 2010 and 13.95 billion gallons in 2011. The mandated usage of renewable fuels increases to 36 billion gallons in 2022. The mandate for corn-based ethanol is capped at 15 billion gallons for the years 2015 through 2022. Certain waiver provisions enable the EPA to reduce the renewable fuel volumetric obligation targets for reasons including severe economic or environmental harm or inadequate domestic supply of renewable fuels.

    Economics of ethanol blending.  As oil prices increased during the commodity bubble of 2007 and 2008, the price of gasoline also increased substantially. The price per gallon of ethanol during this same time period, although increasing, did not keep pace with the increase in the price of gasoline. This phenomenon created an opportunity for refiners and blenders to increase the profitability of the gasoline they sold by blending ethanol in amounts in excess of mandated levels (although not in excess of 10%). This discretionary blending was a driving force behind the rapid growth in the consumption of ethanol in 2007 and the first half of 2008. The profitability of blending ethanol was further enhanced by the VEETC, which was then $0.51 for each gallon of ethanol blended.

    Carryover of Renewable Identification Number credits ("RINS").  Refiners, importers and blenders (other than oxygen blenders) of gasoline are obligated parties under the RFS. The consumption of ethanol above mandated amounts creates an excess of RINS that are available to satisfy an obligated party's blending requirements in the following year. The obligated parties are allowed to meet their requirement to consume renewable fuels through the accumulation or purchase of excess RINS, instead of from the actual physical purchase of renewable fuels. From

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      September 1, 2007 through mid 2008, obligated parties blended significantly more ethanol than was required by the mandate as the economics of blending ethanol were quite profitable. As the blending economics of ethanol became less profitable with the rapid decline in oil prices beginning in the second half of 2008, obligated parties began to apply these excess RINS to meet their obligations which resulted in a significantly reduced demand for ethanol. For 2009, obligated parties blended approximately the same amount of ethanol that was required by the mandate. However, the carryover of 2008 RINS into 2009 created an excess of 2009 RINS that will be available to satisfy an obligated party's blending requirements in 2010. Our view is that there are approximately 1.50 billion RINS available to satisfy an obligated party's requirement for 2010. With the 2010 mandate for renewable biofuels at 12 billion gallons, this means that the actual physical ethanol volume that has to be purchased can be as low as 10.50 billion gallons.

    Emission reduction.  Ethanol is an oxygenate which, when blended with gasoline, reduces vehicle emissions. Ethanol's high oxygen content burns more completely, emitting fewer pollutants into the air. Ethanol demand increased substantially beginning in 1990 when federal law began requiring the use of oxygenates (such as ethanol or methyl tertiary butyl ether ("MTBE")) in reformulated gasoline in cities with unhealthy levels of air pollution on a seasonal or year round basis. Although the federal oxygenate requirement was eliminated in May 2006 as part of the Energy Policy Act of 2005, oxygenated gasoline continues to be used in order to help meet separate federal and state air emission standards. The refining industry has all but abandoned the use of MTBE, making ethanol the primary clean air oxygenate currently used.

    Octane enhancer.  Ethanol, with an octane rating of 113, is used to increase the octane value of gasoline with which it is blended, thereby improving engine performance. It is used as an octane enhancer both for producing regular grade gasoline from lower octane blending stocks (including both reformulated gasoline blendstock for oxygenate blending and conventional gasoline blendstock for oxygenate blending), and for upgrading regular gasoline to premium grades.

    Fuel stock extender.  According to the Energy Information Administration and LEGC, LLC, while domestic petroleum refinery output has increased by approximately 29% from 1980 to 2008, domestic gasoline consumption has increased 36% over the same period, which is the latest period for which information is available. By blending ethanol with gasoline, refiners are able to expand the volume of the gasoline they are able to sell.

    E15 Waiver.  The EPA has under consideration a petition from the renewable fuels trade association Growth Energy to raise the permissible level of ethanol blended into gasoline from 10 to 15 percent, which, if denied, could have an adverse effect on our business, result of operations, and financial condition. In anticipation of reaching market saturation at the current maximum permissible blend level of 10 percent, Growth Energy filed a petition with the EPA in March 2009 requesting a waiver for the use of a higher ethanol blend in gasoline of up to 15 percent for newer cars and trucks. The EPA originally had 270 days to rule on the waiver, but has postponed twice its decision, once to mid-2010 and again to the fall of 2010, to allow the Department of Energy adequate time to complete its testing on the impacts of higher ethanol blend fuels on vehicles. The Department of Energy is testing the impact of a 15 percent ethanol blend, or E15, on model year 2001 and new vehicles, including testing the fuel's impact on catalytic converters, tailpipe and evaporative emissions, fuel system components, engine durability, and on-board diagnostic equipment, as well as related infrastructure including tanks and fuel handling equipment.

      The EPA stated in June 2010 that the Department of Energy is on track to complete testing designed to determine the impact of higher ethanol blends on vehicles built after 2007 by the end of September and that preliminary testing with E15 appeared favorable. On July 1, 2010, the EPA issued a notice announcing the agency will take a bifurcated approach in its decision on the E15 waiver. By the end of this September, the Department of Energy is expected to complete

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      testing on newer vehicles covering the 2007 and younger vehicle fleet, and we believe that the EPA plans to take action at that time on the waiver request regarding the use of E15 in those vehicles. If the test results support the use of E15, the EPA is expected to also propose a labeling rule at that time on fuel dispensing equipment. The Department of Energy is expected to complete testing on vehicles covering the 2001 to 2006 model years in November of this year, at which time we believe that the EPA will make a determination regarding the use of E15 in those vehicles and adjust the label rule if the tests are positive. In its July notice, the EPA also acknowledged that there was insufficient data on the use of E15 in older vehicles and non-road engines to enable the EPA to make a decision on a waiver that would allow the use of E15 for those engines, but that it would review any relevant data submitted prior to making its decision. These most recent statements by the EPA suggest the agency is likely to approve the waiver for model years 2007 and newer vehicles, but not for older vehicles, which would provide a limited incentive for the production of ethanol.

    Growth in E85 usage.  E85 is a blended motor fuel containing up to 85% ethanol. The sale of E85 fuel has historically been less than 1% of the ethanol market (and less than 0.25% of the ethanol we produce). Its growth has been limited by both the availability of E85 fuel to consumers and by the number of automobiles capable of using the fuel. According to E85Prices.com, as of February 9, 2010, only 2,246 gasoline stations across the U.S. sold E85, and there are roughly 9 million flex fuel vehicles on the roads. However, the same website states that the number of stations offering E85 is expected to double in a little over a year as service stations are being offered incentives from Government and Ethanol Industry grants up to $30,000 to install E85 fuel pumps. They also state that General Motors, Ford, and Chrysler have pledged that at least 50% of their production will be flex fuel capable by 2011/2012. These two factors point to a potential growth in the consumption of E85 in future years.

Ethanol Production Processes

        The production of ethanol from corn can be accomplished through one of two distinct processes: wet milling and dry milling. Though the number of dry mill facilities significantly exceeds the number of wet mill facilities, their size is typically smaller. The principal difference between the two processes is the initial treatment of the grain and the resulting co-products. The increased production of higher margin co-products in the wet mill process results in a lower ethanol yield. At a denaturant blend level of 1.96%, a typical wet mill yields approximately 2.5 gallons of ethanol per bushel of corn while a typical dry mill yields approximately 2.7 gallons of fully denatured ethanol per bushel of corn.

Wet Milling

        In the wet mill process, the corn is soaked or "steeped" in water and sulfurous acid for 24 to 48 hours to separate the grain into its many parts. After steeping, the corn slurry is processed to separate the various components of the corn kernel, including the corn germ, which is then sold for processing into corn oil. The starch and any remaining water from the slurry can then be fermented and distilled into ethanol. The ethanol is then blended with a denaturant, such as gasoline, to render it unfit for consumption and thus not subject to the alcohol beverage tax.

        The remaining parts of the grain in the wet mill process are processed into a number of different forms of protein used to feed livestock. The multiple co-products from a wet mill facility generate a higher level of cost recovery from corn than the principal co-product (DDGS) from the dry mill process. In addition, a wet mill, if properly equipped, can produce a higher value brewers' yeast in order to lower its net corn cost. For the years ended December 31, 2009, 2008 and 2007, we recovered 42.7%, 45.6% and 46.3%, respectively, of our total corn costs related to our wet mill process through our sale of co-products and bio-products.

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Dry Milling

        In a dry mill process, the entire corn kernel is first ground into flour, which is referred to in the industry as "meal," and is processed without first separating the various component parts of the grain. The meal is processed with enzymes, ammonia and water, and then placed in a high-temperature cooker to reduce bacteria levels ahead of fermentation. It is then transferred to fermenters where yeast is added and the conversion of sugar to ethanol begins. The fermentation process generally takes between 40 and 50 hours. After fermentation, the resulting liquid is transferred to distillation columns where the ethanol is evaporated from the remaining "stillage" for fuel uses. As with the wet milling process, the ethanol is then blended with a denaturant, such as gasoline, to render the ethanol unfit for consumption and thus not subject to the alcohol beverage tax.

        With the starch elements of the corn kernel consumed in the above described process, the principal co-product produced by the dry mill process is DDGS. DDGS is sold as a protein used in animal feed and recovers a portion of the total cost of the corn, although less than the co-products resulting from the wet mill process described above. For the years ended December 31, 2009, 2008 and 2007, we recovered 25.7%, 26.2% and 26.6%, respectively, of our corn costs related to our dry mill process through the sale of DDGS and other co-products.

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Corn to Ethanol Conversion Process

        The following graphic depicts the corn to ethanol conversion process:

GRAPHIC

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Legislative Drivers and Governmental Regulations

        The U.S. ethanol industry is highly dependent upon federal and state legislation, in particular:

    The EISA;

    The federal ethanol tax incentive program;

    Federal tariff on imported ethanol;

    The use of fuel oxygenates; and

    Various state mandates.

The EISA

        Enacted into law on December 19, 2007, the EISA significantly increases the mandated usage of renewable fuels (ethanol, bio-diesel or any other liquid fuel produced from biomass or biogas). The law increases the RFS originally established under the Energy Policy Act of 2005 to 36 billion gallons by 2022, of which the mandate for corn-based ethanol is limited to 15 billion gallons annually from 2015 through 2022. Waiver provisions enable the EPA to reduce the renewable fuel volumetric obligation targets for reasons including severe economic or environmental harm or an inadequate domestic supply of renewable fuels.

The federal ethanol tax incentive program

        First passed in 1979, the VEETC program allows gasoline distributors who blend ethanol with gasoline to receive a federal excise tax credit for each gallon of ethanol they blend. The federal Transportation Efficiency Act of the 21st Century, or TEA-21, extended the ethanol tax credit first passed in 1979 through 2007. The American Jobs Creation Act of 2004 extended the subsidy again to 2010 by allowing distributors to take a $0.51 excise tax credit for each gallon of ethanol they blend. Under the Food, Conservation and Energy Act of 2008, the tax credit was reduced to $0.45 per gallon for 2009 and thereafter. We cannot give assurance that the tax incentives will be renewed in 2010 or, if renewed, on what terms they will be renewed. Legislation has been introduced in Congress to extend the VEETC at a reduced level, and action is expected on the proposal prior to the November mid-term elections; however, the final outcome remains unclear. See "Risk Factors—The use and demand for ethanol and its supply are highly dependent on various federal and state legislation and regulation, and any changes in legislation or regulation could cause the demand for ethanol to decline or its supply to increase, which could have a material adverse effect on our business, results of operation and financial condition."

Federal tariff on imported ethanol

        In 1980, Congress imposed a tariff on foreign produced ethanol to offset the value of federal tax subsidies. This tariff was designed to protect the benefits of the federal tax subsidies for U.S. farmers. The tariff was originally $0.60 per gallon in addition to a 3.0% ad valorem duty. The tariff was subsequently lowered to $0.54 per gallon with a 2.5% ad valorem duty and was not adjusted completely in direct relative proportion with change in the VEETC. The 2008 Farm Bill extended the $0.54 per gallon tariff on foreign produced ethanol until January 1, 2011. Legislation has been introduced to extend the tariff, although the final outcome remains unclear.

        Ethanol imports from 24 countries in Central America and the Caribbean Islands are exempt from this tariff under the CBI in order to spur economic development in that region. Under the terms of the CBI, member nations may export ethanol into the U.S. up to a total limit of 7% of U.S. production per year (with additional exemptions for ethanol produced from feedstock in the Caribbean region over the 7% limit). In the past, significant imports of ethanol into the U.S. have had a negative effect on

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ethanol prices. See "Risk Factors—The use and demand for ethanol and its supply are highly dependent on various federal and state legislation and regulation, and any changes in legislation or regulation could cause the demand for ethanol to decline or its supply to increase, which could have a material adverse effect on our business, results of operation and financial condition."

Use of fuel oxygenates

        Ethanol is used by the refining industry as a fuel oxygenate which, when blended with gasoline, allows engines to burn fuel more completely and reduce emissions from motor vehicles. The use of ethanol as an oxygenate had been driven by regulatory factors, specifically two programs in the federal Clean Air Act Amendments of 1990, that required the use of oxygenated gasoline in areas with unhealthy levels of air pollution. Although the federal oxygenate requirements for reformulated gasoline included in the Clean Air Act were completely eliminated on May 5, 2006 by the Energy Policy Act of 2005, refiners continue to use oxygenated gasoline in order to meet continued federal and state fuel emission standards.

State Mandates

        Several states, including Florida, Missouri, Montana and Oregon, have enacted mandates that currently, or will in the future, require ethanol blends of 10% in motor fuel sold within the state. Another state, Minnesota, has a 20% renewable fuel mandate that goes into effect in 2013. These mandates help increase demand for ethanol. As more states consider mandates, or if existing mandates are relaxed or eliminated, the demand for ethanol can be affected.

Products

Ethanol

        Our principal product is fuel-grade ethanol, an alcohol which is derived in the U.S. principally from corn. Ethanol is sold primarily for blending with gasoline to meet mandates for the required consumption and use of biofuels, as an octane enhancer, as an oxygenate additive for the purpose of meeting fuel emission standards and as a fuel extender. See "—Industry Overview." For the years ended December 31, 2009, 2008 and 2007, ethanol sales represented 81.5%, 92.5% and 91.3%, respectively, of our total revenue. The reduction in the 2009 percentage of total revenue attributable to ethanol sales is the result of the elimination of the ethanol sales dollars attributable to our marketing alliance and substantial reduction in the ethanol sales dollars attributable to our purchase/resale supply operation from our total revenue numbers for 2009.

Co-Products

        Our Illinois wet mill facility produces co-products such as corn gluten feed (both wet and dry), corn gluten meal, CCDS and corn germ. In addition, the fermentation process yields carbon dioxide. These co-products are sold for various consumer uses into large commodity markets. Corn gluten feed, corn gluten meal and CCDS are used as animal feed ingredients, corn germ is sold for the extraction of corn oil for human consumption, and carbon dioxide is sold for food-grade use such as beverage carbonation and dry ice. Our dry mill facilities in Pekin, Illinois and Aurora, Nebraska produce co-products such as DDGS, WDGS and carbon dioxide. Distillers products are marketed as high protein animal feed and carbon dioxide is sold for beverage carbonation and dry ice. For the years ended December 31, 2009, 2008 and 2007, co-products represented 14.4%, 5.2% and 5.7%, respectively, of our total revenue. The increase in the 2009 percentage of total revenue attributable to co-product sales is the result of the elimination of the ethanol sales dollars attributable to our marketing alliance and substantial reduction in the ethanol sales dollars attributable to our purchase/resale supply operation from our total revenue numbers for 2009.

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Bio-Products

        Our Illinois wet mill facility also produces bio-products, Kosher and Chametz free brewers' yeast, which is processed into a growing variety of products for use in animal and human food and fermentation applications. For the years ended December 31, 2009, 2008 and 2007, bio-products represented 2.1%, 0.5% and 0.6%, respectively, of our total revenue.

Facilities

        The table below provides an overview of our three operational ethanol plants as of December 31, 2009.

 
  Illinois
Wet Mill Facility
  Illinois
Dry Mill Facility
  Nebraska
Facility

Location

  Pekin, Illinois   Pekin, Illinois   Aurora, Nebraska

Ownership

  100.0%   100.0%   100.0%

Land (acres)

  83   11   30

Year constructed

  1981(1)   2007   1995

Process

  Wet Milling   Dry Milling   Dry Milling

Annual ethanol capacity as of December 31, 2009 (in millions of gallons)

  100   57   50

Electricity co-generation capability

  Yes   No   No

Power Source

  Coal, Natural Gas   Natural Gas   Natural Gas

Distribution method

  Rail, Truck, Barge   Rail, Truck, Barge   Rail, Truck

(1)
Illinois wet mill facility converted from corn starches/sweeteners production (built in 1899) to an ethanol facility in 1981.

Marketing Alliances

        Prior to terminating the marketing alliance in late 2008 and early 2009, we sourced ethanol from marketing alliance partners which allowed us to increase sales and enhance our position as a leading player in the ethanol industry. In exchange for allowing us to market their ethanol exclusively, marketing alliance partners gained the benefit of our customer relationships and our ability to distribute ethanol. However, as described above, with severely declining margins and general liquidity stress due to frozen credit markets, this model no longer worked for our alliance partners or us. As such, beginning in the fourth quarter of 2008, we negotiated termination agreements with our marketing alliance partners and began to rationalize our distribution network to primarily focus on sales of our equity production. For the year ended December 31, 2009, we purchased only 30.9 million gallons of ethanol from marketing alliance partners. We recognized $10.2 million of income from the termination of our marketing alliance agreements in 2009. During the years ended December 31, 2008 and 2007, we purchased 505.3 million and 395.0 million gallons, respectively, of ethanol produced by our marketing alliance partners.

        As part of our new marketing strategy geared toward our equity production, we significantly reduced our fixed costs associated with our distribution network.

Sales and Marketing

        We employ direct sales personnel to pursue sales opportunities. In addition, customer service representatives are available to respond to customer questions and to undertake or resolve any required customer service issues. Our sales structure forms an integral, critical link in communicating

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with our customers. The sales function is coordinated through key senior executives responsible for our sales and marketing efforts.

Distribution and Logistics

        Due to severely declining margins and general liquidity stress due to frozen credit markets, we have significantly reduced the number of gallons we source from third parties. As noted above, beginning in the fourth quarter of 2008 we began negotiating termination agreements with most of our marketing alliance partners and terminated all of them during 2009. We recognized $10.2 million of income from the termination of our marketing alliance agreements during 2009. Accordingly, we have also undertaken a strategy to rationalize our distribution and logistics system to focus primarily on our equity production. At December 31, 2008, we had signed agreements for leased terminal capacity at 57 terminal locations. During 2009, we subleased or assigned the majority of our railcar, barge and terminal leases. We have aligned our distribution network in relation to production volumes from our equity-owned ethanol production facilities, and this distribution network has a cost structure that is comprised of minimal fixed cost commitments and is operated primarily on a variable cost basis. At December 31, 2009, we had signed agreements for leased terminal capacity at only three terminal locations.

        The costs associated with leasing these terminals were previously factored into the purchase price we paid our marketing alliance partners for the ethanol that we purchased from them and, therefore, a portion of these leasing costs were effectively paid for by our marketing alliance partners.

Customers

        The substantial majority of our customer base has purchased ethanol from us for over five years (including our predecessor companies). In 2009, 2008 and 2007, our ten largest customers accounted for approximately 66%, 50% and 67%, respectively, of our consolidated ethanol sales volume.

        For the 2009 fiscal year, Biourja Trading accounted for 10.5% and Exxon Mobil accounted for 11.1% of our consolidated net sales volume. No other customers in fiscal 2009 represented more than 10% of our consolidated net sales volume. No customers in 2008 or 2007 represented more than 10% of our consolidated net sales volume.

Competition

        According to the RFA, there were 122 producers operating 185 ethanol plants in the U.S. as of December 31, 2009. The top ten producers accounted for approximately 47.9%, 46.6%, and 54.3% of total industry capacity for the years 2009, 2008, and 2007, respectively. Aventine was one of the top ten producers, which all have annual production capacity exceeding 200 million gallons per year.

        A significant development during 2009 was Valero Energy's acquisition of ten ethanol plants from VeraSun Energy and Renew Energy. As a result of the acquisitions, the second largest U.S. oil refiner is now a top ten producer with annual ethanol production capacity of approximately 1 billion gallons.

        The remaining producers consist primarily of small capacity producers and farmer cooperatives.

        The world's ethanol producers have historically competed primarily on a regional basis. Imports into the U.S. have generally been limited by an import tariff of $0.54 per gallon (other than from Caribbean basin countries which are exempt from this tariff up to specified limits).

        Certain of our competitors have significantly larger market shares than we have, and tend to be price leaders in the industry. If any of these competitors were to significantly reduce their prices, our business, operating results and financial condition could be adversely affected.

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        We could also be adversely affected if new products or technologies emerge that reduce or eliminate the need for ethanol. Our ethanol production is corn based, and competes with ethanol made from alternative materials, such as sugar, wheat and sorghum. Cellulosic sources of materials may also become a substitute feedstock for ethanol production, or other products may be devised which eliminate the need for ethanol entirely. Periods of time with sustained high corn prices could decrease the relative attractiveness of corn-based ethanol where alternatives exist, thereby adversely affecting our business, operating results or financial condition.

Investments

        Historically, we had made minority investments in other ethanol producers. Investments made by the Company in other ethanol producers after May 31, 2003 were recorded at cost, including our investment in Indiana BioEnergy ("IBE") prior to its acquisition by Green Plains Renewable Energy ("GPRE"). Our investment in IBE was valued at December 31, 2007 at our initial investment cost of $5.0 million. On October 15, 2008, IBE merged with GPRE, a publicly held company whose shares are traded on the NASDAQ national market, and our $5.0 million original investment was converted to 365,999 shares of GPRE stock. On October 15, 2008, we recorded a loss of $2.8 million on the exchange and reduced the value of our investment from $5.0 million to $2.2 million, which was the market price of the GPRE shares at that date. As our investment in GPRE shares is considered an available for sale investment in accordance with Accounting Standards Codification 320, Investments—Debt and Equity Securities, we recognized an other than temporary loss of $1.5 million on December 31, 2008. We made our determination that the loss in GPRE stock was other than temporary, considering our lack of ability and intent to hold this security to recover its value given our liquidity situation at that time. The GPRE stock has recovered significantly. Our recorded investment in GPRE at December 31, 2009, based upon the closing price of GPRE stock on the last trading day of 2009, is now carried at $5.4 million.

        During 2009, we sold our interests in Ace Ethanol, LLC and Granite Falls Energy LLC, recording gains totaling $1.0 million.

Pricing and Backlog

        Historically, ethanol delivered to customers was priced in accordance with one of the following methods: (i) a negotiated fixed contract price per gallon, (ii) a price per gallon based on an average spot value of ethanol at the time of shipment plus or minus a fixed amount, or (iii) a price per gallon based on the market value of wholesale unleaded gasoline plus or minus a fixed amount. The Company believed these pricing strategies, in conjunction with the rapid turnover of its inventory, provided a natural hedge against changes in the market price of ethanol. Currently the majority of ethanol sold to customers is based upon a spot index price.

        As of December 31, 2009, we had contracts for delivery of ethanol totaling 57.3 million gallons through September 30, 2010, all at spot prices (using various Platt, OPIS and AXXIS indices).

Raw Materials and Suppliers

        Our principal raw material is #2 yellow corn. In 2009, 2008 and 2007, we purchased approximately 74.2 million, 71.4 million and 71.9 million bushels of corn, respectively.

        We contract for our corn requirements through a variety of sources, including farmers, grain elevators, and cooperatives. Due to our plants being located in or near the Midwestern portion of the U.S., we believe that we have ample access to various corn markets and suppliers. Although corn can be obtained from multiple sources, and while historically we have not suffered any significant limitations on our ability to procure corn, any delay or disruption in our suppliers' ability to provide us with the necessary corn requirements may significantly affect our business operations and have a negative effect on our operating results or financial condition. At any given time, we may have up to 1.0 million bushels (or a 4 to 5 day supply) of corn stored on-site at our production facilities.

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        The key elements of our corn procurement strategies are the assurance of a stable supply and the avoidance, where possible, of significant exposures to corn price fluctuations. Corn prices fluctuate daily, typically using the CBOT price as a benchmark. Corn is delivered to our facilities via truck through local distribution networks and by rail.

Patents and Trademarks

        We own several patents, patent rights and trademarks within the U.S. We do not consider the success of our business, as a whole, to be dependent on these patents, patent rights or trademarks.

Environmental and Regulatory Matters

        We are subject to extensive federal, state and local environmental, health and safety laws, regulations and permit conditions (and interpretations thereof), including, among other things, those relating to the discharge of hazardous and other waste materials into the air, water and ground, the generation, storage, handling, use, transportation and/or disposal of hazardous materials, and the health and safety of our employees. Compliance with these laws, regulations, and permits require us to incur significant capital and other costs, including costs to obtain and maintain expensive pollution control equipment. These regulations may also require us to make operational changes to limit actual or potential impacts to the environment. A violation of these laws, regulations or permit conditions can result in substantial administrative and civil fines and penalties, criminal sanctions, imposition of clean-up and site restoration costs and liens, suspension or revocation of necessary permits, licenses and authorizations and/or the issuance of orders enjoining or limiting our current or future operations. In addition, environmental laws and regulations (and interpretations thereof) change over time, and any such changes, more vigorous enforcement policies or the discovery of currently unknown conditions may require substantial additional environmental expenditures.

        We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged for the disposal of hazardous wastes. For instance, over ten years ago soil and groundwater contamination from fuel oil contamination at a storage site was identified at our Illinois campus. The fuel oil tanks were removed and a portion of the area has been capped, but no remediation has been performed. If any of these sites are subject to investigation and/or remediation requirements, we may be incur strict and/or joint and several liability under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws which impose strict liability for all or part of the costs of such investigation, remediation, or removal costs and for damages to natural resources whether the contamination resulted from the conduct of other or from consequences of our own actions that were or were not in compliance with applicable laws at the time those actions were taken. We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties or other impacts of our operations. While costs to address contamination or related third-party claims could be significant, based upon currently available information, we are not aware of any material liability relating to contamination or such third party claims. We have not accrued any amounts for environmental matters as of June 30, 2010. The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

        In addition, the hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, abnormal pressures and spills) may result in releases of hazardous substances and other waste materials, and may result in claims from governmental authorities or third parties relating to actual or alleged personal injury, property damage, or damages to natural resources. We maintain insurance coverage against some, but not all, potential losses associated with our operations. Our coverage includes, but is not limited to, physical damage to assets, employer's liability, comprehensive general liability, automobile liability and workers' compensation. We do not carry

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environmental insurance. We believe that our insurance is adequate for our industry, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of events which result in significant personal injury or damage to our property, natural resources or third parties that is not covered by insurance could have a material adverse impact on our results of operations and financial condition.

        Our air emissions are subject to the federal Clean Air Act, as amended, and similar state laws which generally require us to obtain and maintain air emission permits for our ongoing operations, as well as pre-approval for any expansion or construction of existing facilities or new facilities or modification of certain projects or facilities. Obtaining and maintaining those permits requires us to incur costs, and any future more stringent standards may result in increased costs and may limit or interfere with our operations. In addition, the permits ultimately issued may impose conditions which are more costly to implement than we had anticipated. These costs could have a material adverse effect on our financial condition and results of operations. Our failure to comply with air emissions laws and regulations could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. Because other ethanol manufacturers in the U.S. are and will continue to be subject to similar laws and restrictions, we do not currently believe that our costs to comply with current or future air emissions laws and regulations will adversely affect our competitive position among domestic producers. However, because ethanol is produced and traded internationally, these costs could adversely affect us in our efforts to compete with foreign producers not subject to such stringent requirements.

        Federal and state environmental authorities have been investigating alleged excess VOCS emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities. The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility. If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar investigation at our Nebraska facility due to the larger size of the Illinois wet mill facility. As of yet we have not established reserves for possible costs we may incur in connection with this investigation. In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.

        We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the NESHAP for industrial, commercial and institutional boilers and process heaters, which was issued but subsequently vacated. The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers. The EPA is currently rewriting the NESHAP, which is expected to be more stringent than the vacated version. In the absence of a final NESHAP for industrial, commercial and institutional boilers and process heaters, we are waiting for state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed. We currently cannot estimate the amount that will be needed to comply with any future federal or state technology requirement regarding air emissions from our boilers.

        In June 2009, the U.S. House of Representatives pass the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill. The U.S. Senate is considering a number of comparable measures. One such measure, the Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, has been reported out of the Senate Committee on Energy and Natural Resources, but has not yet been considered by the full Senate. Although these bills include several differences that require reconciliation before becoming law, both contain the basic feature of establishing a "cap and trade" system for restricting greenhouse gas emissions in the U.S. Under such system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission "allowances"

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corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this legislative initiative remains uncertain. Any laws or regulations that may be adopted to restrict or reduce emissions of U.S. greenhouse gases could require us to incur increased operating costs, and could have an adverse effect on the revenues we generate from carbon dioxide sales. In addition, at least 20 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.

        Depending on the particular program, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Although we would not be impacted to a greater degree than other similarly situated companies, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce the revenues we generate from carbon dioxide sales.

        On April 2, 2007, the U.S. Supreme Court found that the EPA has the authority to regulate carbon dioxide emissions from automobiles as "air pollutants" under the Clean Air Act. Although this decision did not address carbon dioxide emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate "air pollutants" from those and other facilities. On April 17, 2009, the EPA released a "Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act." The EPA's proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA's proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA's proposed findings do not specifically address stationary sources, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources. On September 23, 2009, the EPA finalized a greenhouse gas reporting rule establishing a national greenhouse gas emissions collection and reporting program. The EPA rules will require covered entities to measure greenhouse gas emissions commencing in 2010 and submit reports commencing in 2011. On September 30, 2009, the EPA proposed new thresholds for greenhouse gas emissions that define when Clean Air Act permits under the New Source Review and Title V operating permits programs would be required. Under the Title V operating permits program, the EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalency for existing industrial facilities. Facilities with greenhouse gas emissions below this threshold would not be required to obtain an operating permit. Under the Prevention of Significant Deterioration portion of the New Source Review, the EPA is proposing a major stationary source threshold of 25,000 tpy of carbon dioxide equivalency. This threshold level would be used to determine if a new facility or a major modification at an existing facility would trigger Prevention of Significant Deterioration permitting requirements. The EPA is also proposing a significance level between 10,000 and 25,000 tpy of carbon dioxide equivalency. Existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a Prevention of Significant Deterioration permit. The EPA is requesting comment on a range of values in this proposal, with the intent of selecting a single value for the greenhouse gas significance level. These proposals, along with new federal or state restrictions on emissions of carbon dioxide that may be imposed in areas of the U.S. in which we conduct business could also adversely affect our cost of doing business and demand for the ethanol we produce.

        On February 3, 2010 the EPA announced final revisions to the National Renewable Fuel Standard program (commonly known as the RFS program or RFS-2). This Rule makes changes to the RFS

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program as required by the EISA. The revised statutory requirements establish new specific annual volume standards for cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel that must be used in transportation fuel. The revised statutory requirements also include new definitions and criteria for both renewable fuels and the feedstock used to produce them, including new greenhouse gas emission thresholds as determined by lifecycle analysis. The regulatory requirements for RFS-2 will apply to domestic and foreign producers and importers of renewable fuel used in the U.S.

        This final action is intended to lay the foundation for achieving significant reductions of greenhouse gas emissions from the use and creation of renewable fuels, reductions of imported petroleum and further development and expansion of our nation's renewable fuels sector.

        On May 10, 2010, the EPA published a Direct Final Rule to "amend certain of the RFS program regulations" to correct "some technical errors and areas within the final RFS-2 regulations that could benefit from clarification or modification." As part of this Direct Final Rule, the EPA revised the RFS-2 "to require that construction of grandfathered renewable fuel production facility for which construction commenced prior to December 19, 2007, be completed by December 19, 2010, rather than 36 months from the date of commencement of construction." The Direct Final Rule is effective as of July 1, 2010, except for sections upon which the EPA received adverse comment or request for a hearing. We are unaware of adverse comment or request for a hearing on the construction deadlines described above.

        This Rule sets the 2010 RFS volume standard at 12.95 billion gallons (bg). Further, for the first time, the EPA is setting volume standards for specific categories of renewable fuels including cellulosic, biomass-based diesel, and total advanced renewable fuels. For 2010, the cellulosic standard is set at 6.5 million gallons (mg); and the biomass based diesel standard is set at 1.15 bg, (combining the 2009 and 2010 standards as proposed).

        In order to qualify for these new volume categories, fuels must demonstrate that they meet certain minimum greenhouse gas reduction standards, based on a lifecycle assessment, in comparison to the petroleum fuels they displace. Generally, ethanol plants either must meet the 20% reduction test or are grandfathered under special provisions. For plants under construction on which construction commenced prior to December 19, 2007 (including the company's Mt. Vernon and Aurora West plants under construction) the plants must be completed within 36 months in order to meet the requirements to be grandfathered or comply with the greenhouse gas reduction standards which require the use of Advanced Technologies defined by the regulations.

        For more information about our environmental compliance and actual and potential environmental liabilities, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Uses of Liquidity—Capital Expenditures" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Environmental Matters."

Employees

        At June 30, 2010, we had a total of 305 full-time equivalent employees, compared to 302 as of December 31, 2009 and 346 as of December 31, 2008. On March 13, 2009, we instituted a reduction in force of 26 employees, primarily as a result of the termination of our marketing alliance. Approximately 55% of our current full-time employees (comprised of the hourly employees at our Illinois facilities) are represented by a union. The unionized employees are covered by a collective bargaining agreement between our subsidiary, Aventine Renewable Energy, Inc. and the United Steelworkers International Union, Local 7-662 (the "Union"). Our contract with the Union was scheduled to expire in October 2009. Prior to the expiration of the collective bargaining agreement, the Company and the Union agreed to extend the term of the current collective bargaining agreement by one year through and including October 31, 2010 on the same terms and conditions. There can be no assurances that we will

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be able to timely and successfully negotiate a new labor contract whose terms allow us to operate our business in today's difficult operating environment. If we are unable to timely and successfully negotiate a new labor contract, our business may be disrupted and our results of operations and financial condition may be negatively affected.

Legal Proceedings

        On November 6, 2008, Aventine Renewable Energy, Inc. filed a complaint against JPMorgan Securities, Inc. and JPMorgan Chase Bank, N.A. in the Circuit Court for the Tenth Judicial Circuit of Tazewell County, Illinois. We are seeking to recover $31.6 million lost in the investment of funds in student loan backed auction rate securities. We have alleged that JPMorgan Chase Bank through its investment arm, JPMorgan Securities, gave false assurances of the liquidity of this type of investment. The $31.6 million figure represents funds lost because we were forced to sell the investment at a loss after they became illiquid; the investment monies were earmarked to fund our expansion activities. There can be no assurance either that we will be successful in recovering any of these amounts or as to the timing of any such recovery pursuant to this litigation.

        We are from time to time involved in various legal proceedings, including legal proceedings relating to the extensive environmental laws and regulations that apply to our facilities and operations, including those described under "Management's Discussion and Analysis of Financial Condition and Results of Operations—Environmental Matters," which is incorporated herein by reference. We are not involved in any legal proceedings that we believe will have a material adverse effect upon our business, operating results or financial condition.

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MANAGEMENT

Directors and Executive Officers

        Set forth below is certain information regarding our executive officers and directors as of the date of this prospectus.

Name
  Age   Position

Thomas L. Manuel

    63   Chief Executive Officer, Chief Operating Officer and Director

John W. Castle

    46   Chief Financial Officer

William J. Brennan

    59   Chief Accounting and Compliance Officer

Benjamin J. Borgen

    36   Senior Vice President, Commodity Risk Management

Eugene I. Davis

    55   Chairman of the Board of Directors

Timothy J. Bernlohr

    51   Director and Chairman of the Compensation Committee

Kurt M. Cellar

    40   Director and Chairman of the Audit Committee

Douglas Silverman

    32   Director

Carney Hawks

    35   Director

Executive Officers

        Thomas L. Manuel    Mr. Manuel was appointed Chief Executive Officer, Chief Operating Officer and a Director in March 2010. From November 2008 until March 2010, Mr. Manuel worked as a consultant for CRG Partners, LLC, a privately held business management firm, and from August 2007 until November 2008, Mr. Manuel managed personal investments. From August 2006 until August 2007, Mr. Manuel was the President and Chief Executive Officer of ASAlliances Biofuels LLC ("ASA") and a member of its board of directors. Prior to that, Mr. Manuel was the President and Chief Operating Officer of ConAgra Meat Companies ("ConAgra Meat") from 1998 until 2000. Prior to ConAgra Meat, Mr. Manuel was President and Chief Operating Officer of ConAgra Trading and Processing from 1994 until 1998. Mr. Manuel began his career at ConAgra Foods ("ConAgra") in 1977. While at ConAgra, Mr. Manuel was part of a team that helped drive sales from $480 million to $23 billion. He served as assistant to the Chairman of ConAgra and general manager of several ConAgra business units, where he was responsible for ConAgra's international and domestic grain merchandising business. Mr. Manuel received his B.S. degree in Business Administration from the University of Minnesota. In between his time at ConAgra Meat and ASA, Mr. Manuel served on the boards of various companies, including Swift & Company and Data Transmission Network Corporation. Our Board of Directors has determined that Mr. Manuel should serve as a director based on his extensive experience as an executive in our industry and his experience and insight as our Chief Executive Officer.

        John W. Castle    Mr. Castle was appointed Chief Financial Officer in April 2010. Before joining the Company, Mr. Castle served as Senior Vice President of Operations and Chief Financial Officer of White Energy, Inc., an ethanol production company, starting in November 2005. From August 2004 to November 2005, Mr. Castle was director of accounting for Dresser, Inc., a global manufacturer of highly engineered energy infrastructure and oilfield products and services. Mr. Castle has also served as Vice President and Chief Financial Officer at Rohn Industries, Inc. and as Vice President, Treasurer and Corporate Controller of Telxon Corporation. Previously, Mr. Castle was a member of Paxton Associates LLC, a provider of financial and operational assessment services. Mr. Castle has also held accounting and financial management positions at Mosler Inc. and Litton Industries, Inc. Mr. Castle is a Certified Public Accountant with a Masters of Business Administration from Xavier University and a Bachelor of Science in Accounting from Eastern Illinois University.

        William J. Brennan    Mr. Brennan became our Chief Accounting & Compliance Officer in November 2005 and was our Chief Financial Officer from October 2004 when he joined the Company, until November 2005. Before joining the Company, Mr. Brennan served as Regional Chief Financial

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Officer for Omnicare Inc. from 2001 to 2004 and as Chief Financial Officer of Polestar Communications, Inc. and its predecessor company from 2000 to 2001. Mr. Brennan also held senior financial positions with Ameritech Inc., Wisconsin Bell, Inc. and De La Rue Systems of the Americas, Inc. Mr. Brennan began his professional career with Alexander Grant & Co. Certified Public Accountants. Mr. Brennan is a Certified Public Accountant with a Masters of Business Administration from Marquette University and a Bachelor of Business Administration in Accounting from the University of Wisconsin—Milwaukee.

        Benjamin J. Borgen    Mr. Borgen became our Senior Vice President, Commodity Risk Management in March 2010. From June 2009 to February 2010, Mr. Borgen managed ethanol trading as Director of Commodity Trading for Barclays Capital. From April 2008 to May 2009, Mr. Borgen served as Director of Ethanol Trading at Saracen Energy Partners. Mr. Borgen served as Vice President of Ethanol Trading and Marketing for Sempra Energy Trading, from March 2005 to March 2008. Mr. Borgen was also a Senior Energy Trader with PG&E National Energy Group. In these positions, Mr. Borgen was responsible for strategy development and evaluation, asset evaluation, and management of commodity positions. Mr. Borgen holds a Bachelor of Arts degree from Concordia College in Moorhead, Minnesota.

Directors

        Eugene I. Davis    Mr. Davis became Chairman of the Board in March 2010. Mr. Davis is currently Chairman and Chief Executive Officer of PIRINATE Consulting Group, LLC ("PIRINATE"), a privately held consulting firm specializing in turnaround management, merger and acquisition consulting and hostile and friendly takeovers, proxy contests and strategic planning advisory services for domestic and international public and private business entities. Since forming PIRINATE in 1997, Mr. Davis has advised, managed, sold, liquidated and served as a Chief Executive Officer, Chief Restructuring Officer, Director, Committee Chairman and Chairman of the Board of a number of businesses operating in diverse sectors such as telecommunications, automotive, manufacturing, high-technology, medical technologies, metals, energy, financial services, consumer products and services, import-export, mining and transportation and logistics. Previously, Mr. Davis served as President, Vice Chairman and Director of Emerson Radio Corporation and Chief Executive Officer and Vice Chairman of Sport Supply Group, Inc. He began his career as an attorney and international negotiator with Exxon Corporation and Standard Oil Company (Indiana) and as a partner in two Texas-based law firms, where he specialized in corporate/securities law, international transactions and restructuring advisory. Mr. Davis graduated with a B.A. degree in International Politics from Columbia University and graduated with a Masters in International Affairs degree in International Law and Organization from the School of International Affairs of Columbia University and a J.D. from Columbia University School of Law. Mr. Davis is also a member of the board of directors of American Commercial Lines, Inc., Atlas Air Worldwide Holdings, Knology, Inc., Bally Total Fitness, Solutia Inc. and TerreStar Corporation. Since 2005, Mr. Davis has been a director of Exide, IPCS, Oglebay Norton, Tipperary Corporation, Viskase, Inc., McLeod Communications, Granite Broadcasting, Footstar, PRG Schultz, Silicon Graphics, SeraCare, Foamex, Ion Broadcasting, Delta Airlines, Atari, Media General, Rural/Metro, Spectrum Brands, Ambassadors, and DEX One. Our Board of Directors has determined that Mr. Davis should serve as a director and as Chairman of the Board based on his extensive experience as a chairman and director of emerging companies as well as his management and legal expertise.

        Timothy J. Bernlohr    Mr. Bernlohr has been a Director since March 2010. Mr. Bernlohr is the founder and, since November 2004, has been a managing member of TJB Management Consulting, LLC, which specializes in providing project specific consulting services to businesses in transformation, including restructurings, interim executive management and strategic planning services. From April 1997 to July 2005, Mr. Bernlohr held positions of increasing authority with RBX

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Industries, Inc. ("RBX"), including serving as its President and Chief Executive Officer. RBX was a nationally recognized leader in the design, manufacture and marketing of rubber and plastic materials to the automotive, construction and industrial markets. RBX filed a voluntary petition for reorganization under Chapter 11 in March 2004 and was sold to multiple buyers in 2004 and 2005. Prior to joining RBX in 1997, Mr. Bernlohr spent 16 years in the International and Industry Products division of Armstrong World Industries, where he served in a variety of management positions. Mr. Bernlohr is chairman of the boards of directors of Champion Home Builders, Inc., The Manischewitz Company and Cuisine Innovations and a director of Atlas Air Worldwide Holdings, Inc, Bally Total Fitness Corporation, Hayes Lemmerz Inc., Ambassadors International, Inc. and Hilite International. Mr. Bernlohr was formerly a director of WCI Steel from May 2006 to June 2008. Mr. Bernlohr is a graduate of The Pennsylvania State University. Our Board of Directors has determined that Mr. Bernlohr should serve as a director based on his extensive executive experience and his prior and ongoing board service for other public companies.

        Kurt M. Cellar    Mr. Cellar has been a Director since March 2010. Mr. Cellar has been a self-employed consultant and board member since January 2008. From July 1999 through January 2008, Mr. Cellar was a partner and Portfolio Manager at Bay Harbour Management, L.C. ("Bay Harbour"). Prior to Bay Harbour, he was an associate at Remy Investors and Consultants, Inc. ("Remy"), where he sourced and analyzed public and private investment opportunities. Prior to Remy, Mr. Cellar was an associate at LEK/Alcar Consulting Group, Inc., a strategic management consulting firm. Mr. Cellar received a B.A. degree in Economics and Business from the University of California, Los Angeles and his M.B.A. in Finance and Entrepreneurial Management from the Wharton School at the University of Pennsylvania. Mr. Cellar currently serves on the boards of Home Buyers Warranty, Inc. the Penn Traffic Company and RCN Corporation. Our Board of Directors has determined that Mr. Cellar should serve as a director based on his extensive financial, accounting, and investing experience and his prior and ongoing board service for other public companies.

        Douglas Silverman    Mr. Silverman has been a Director since March 2010. Mr. Silverman is a Managing Partner and Co-Chief Investment Officer at Senator Investment Group LP ("Senator") where he is responsible for portfolio management and all operations of a 16 employee partnership which manages approximately $1.9 billion of assets. Prior to co-founding Senator in February 2008, Mr. Silverman was a Managing Director and Co-Portfolio Manager at York Capital Management ("York") from May 2002 to December 2007. Prior to joining York, Mr. Silverman was an investment banker in the Leveraged Finance department at Merrill, Lynch & Co. from June 2000 to April 2002. Mr. Silverman received a B.A. in Economics, cum laude, from Princeton University. Our Board of Directors has determined that Mr. Silverman should serve as a director based on his extensive financial, accounting, and investing experience.

        Carney Hawks    Mr. Hawks has been a Director since March 2010. Mr. Hawks is an original partner with Brigade Capital Management, LLC ("Brigade"), a credit-focused, asset management firm founded in 2007. Prior to joining Brigade, he was a Managing Director in the High Yield Division of MacKay Shields ("MacKay") from 1998 through 2006. Prior to MacKay, he was an investment banker in the Financial Entrepreneurs Group at Salomon Smith Barney. Mr. Hawks is a graduate (with Distinction) of the University of Virginia's McIntire School of Commerce and a CFA Charterholder. He currently serves on the board of Jacuzzi Group Worldwide. Our Board of Directors has determined that Mr. Hawks should serve as a director based on his extensive financial and investing experience.

Board Composition

        Under our third amended and restated certificate of incorporation and amended and restated bylaws, the number of directors at any one time are set by resolution of the Board. Currently, the Board consists of six members, of which three have affirmatively been determined to be independent.

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Our former Board affirmatively determined that all seven members—Messrs. Leigh Abramson, Theodore Butz, Richard Derbes, Farokh Hakimi, Michael Hoffman, Wayne Kuhn and Arnold Nemirow, all of whom were replaced upon our emergence from bankruptcy—were independent of the Company and our management. In making such determination, the former Board took into account the matters described under "Certain Relationships and Related Transactions—The MSCP Funds and Metalmark Capital LLC." Upon emergence from bankruptcy and appointment of our new Board, the Board affirmatively determined that Messrs. Davis, Bernlohr and Cellar are independent of the Company and our management under the NASDAQ Stock Market Rules and Rule 10A-3 of the Exchange Act. In addition, although the Board has not made a formal determination on the matter, we believe that Messrs. Hawks and Silverman may not be independent of the Company and our management under the NASDAQ Stock Market Rules. In making this independence determination, we noted in particular the following: (i) Mr. Hawks is an original partner with Brigade, (ii) Mr. Silverman is a Managing Partner and Co-Chief Investment Officer with Senator, (iii) Brigade received approximately 27% in aggregate principal amount of Notes and shares of common stock sold in a private placement that closed on March 15, 2010, (iv) Senator received approximately 12% in aggregate principal amount of Notes and shares of common stock sold in a private placement that closed on March 15, 2010, and (v) Senator and Brigade received an aggregate of $500,000 as a commitment fee as consideration for their commitment to backstop our August 2010 Notes offering. See "Certain Relationships and Related Party Transactions—Transactions with Executive Officers and Directors—The Backstop Purchasers."

        We note that The NASDAQ Stock Market LLC does not view ownership of even a significant amount of stock, by itself, as a bar to an independence finding. Although it is unclear under NASDAQ Stock Market Rules whether Messrs. Hawks and Silverman would be considered independent, we do not believe that any of the above factors would cause either of Messrs. Hawks or Silverman to have a relationship with us that would impair their independence for the purposes of NASDAQ Stock Market Rule 5605(a)(2).

        Our third amended and restated certificate of incorporation and amended and restated bylaws provide for the annual election of directors. At each annual meeting of stockholders, beginning at our 2011 annual meeting, our directors will be elected for a one-year term and serve until their respective successors have been elected and qualified. It is anticipated that the Board of Directors will meet at least quarterly.

        Stockholders desiring to communicate with the Board may do so by mail addressed as follows: Board of Directors, Aventine Renewable Energy Holdings, Inc., 120 North Parkway Drive, Pekin, IL 61554. We believe our responsiveness to stockholder communications to the Board has been excellent.

        The Company encourages, but does not require, directors to attend annual meetings of stockholders.

Board Committees and Director Nominations

        Prior to March 2010, we had an audit committee which consisted of Messrs. Farokh Hakimi, Richard Derbes and Arnold Nemirow. Prior to March 2010, we had a compensation committee which consisted of Messrs. Wayne Kuhn, Leigh Abramson and Arnold Nemirow. In March 2010, we reconstituted our Board of Directors pursuant to our plan of reorganization. In accordance with our plan of reorganization, Messrs. Davis, Cellar, Silverman and Hawks were appointed to the Board by Brigade, Nomura Corporate Research & Asset Management, Inc., Whitebox Advisors, LLC, Senator and SEACOR Capital Corporation (the "Backstop Purchasers"), which constituted a group that formerly held (or managed affiliated funds or accounts that formerly held) the Old Notes that were cancelled pursuant to our plan of reorganization. Mr. Manuel, as Chief Executive Officer, was also

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appointed to our Board of Directors pursuant to our plan of reorganization. On March 15, 2010 our Board of Directors voted to increase the size of the Board by one and Mr. Bernlohr was selected to fill the resulting vacancy. We consequently reconstituted our audit committee and compensation committee and, in April 2010, we established a strategic and finance committee. The Board of Directors will also establish such other committees as it deems appropriate, in accordance with applicable law and regulations and our third amended and restated certificate of incorporation and amended and restated bylaws.

        Audit Committee.    We have an audit committee that is comprised of three directors (Messrs. Cellar (Chair), Davis and Bernlohr), all of whom are "independent" as defined under the federal securities laws. Mr. Cellar is designated as the "audit committee financial expert," as defined by Item 401(h) of Regulation S-K of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). The principal duties of the audit committee are as follows:

    to select the independent auditor to audit our annual financial statements;

    to approve the overall scope of and oversee the annual audit;

    to assist the Board of Directors in monitoring the integrity of our financial statements, the independent auditor's qualifications and independence, the performance of the independent auditor and our internal audit function and our compliance with legal and regulatory requirements;

    to review and discuss with management the annual audited financial and quarterly statements with management and the independent auditor;

    to discuss policies with respect to risk assessment and risk management; and

    to review with the independent auditor any audit problems or difficulties and management's responses.

In addition, our audit committee is responsible for assisting the Board in monitoring our Company's compliance with legal and regulatory requirements and for developing and recommending to the Board a set of corporate governance guidelines.

        Our Board of Directors has adopted a written charter for the audit committee, which is available on our website.

        Compensation Committee.    We have a compensation committee that includes Mr. Bernlohr (Chair), Mr. Davis and Mr. Cellar, all of whom are "independent" as defined under the federal securities laws. The compensation committee will administer, subject to Board approval, our stock plans and incentive compensation plans, including our 2010 Equity Incentive Plan. In addition, the compensation committee will be responsible for making recommendations to the Board of Directors with respect to the compensation of our Chief Executive Officer and our other executive officers and for making recommendations to the Board of Directors with respect to compensation and employee benefit programs.

        Our Board of Directors has adopted a written charter for the compensation committee, which is available on our website.

        Strategic and Finance Committee.    We have a strategic and finance committee that includes Mr. Hawks (Chair), Mr. Davis and Mr. Silverman. The strategic and finance committee will review possible financing, purchase, sale and other strategic transactions involving the Company and present such transactions to the Board of Directors.

        Director Nominations.    The Board has not established a committee responsible for nominating, or recommending for nomination, directors to our Board. We believe that the entire Board is able to

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fulfill the functions of a nominating committee. The Board believes that candidates for director should have certain minimum qualifications, including being able to read and understand financial statements and having the highest personal integrity and ethics. The Board will consider such factors as relevant expertise and experience, ability to devote sufficient time to the affairs of the Company, demonstrated excellence in his or her field, the ability to exercise sound business judgment and the commitment to rigorously represent the long-term interests of the Company's stockholders. Candidates for director will be reviewed in the context of the current composition of the Board, the operating requirements of the Company and the long-term interests of stockholders. The Board currently does not have a formal process in place for identifying and evaluating nominees for directors. Instead, the Board will use its network of contacts to identify potential candidates. The Board will conduct any appropriate and necessary inquiries into the backgrounds and qualifications of possible candidates after considering the function and needs of the Board. The Board has not established procedures for considering nominees recommended by stockholders. The Board believes that nominees should be considered on a case-by-case basis on each nominee's merits, regardless of who recommended such nominee.

Board Leadership Structure

        Our Chairman of the Board sets the agenda for each of our Board meetings and generally presides over the meetings of our Board of Directors. However, each of our directors is expected to provide leadership for our Board of Directors in the areas where they have particular expertise and each of our Board members from time to time suggests topics for inclusion on the agenda for future Board meetings. We believe that our leadership structure is appropriate because it strikes an effective balance between management and non-employee director participation in the Board process. The role of our Chief Executive Officer, who is also a director, helps to ensure communication between management and the non-employee directors, but also encourages each non-employee director to participate and contribute to the Board process, while also capitalizing on each director's particular area of expertise as needed. It also increases the non-employee directors' understanding of management decisions and our operations.

Board Risk Assessment and Control

        Our risk management program is overseen by our Board of Directors and its committees, with support from our management. Our Board of Directors oversees an enterprise-wide approach to ethanol industry risk management, designed to support the achievement of organizational objectives, including strategic objectives, to improve long-term organizational performance and enhance shareholder value. A fundamental part of risk management is a thorough understanding of the risks a company faces, understanding of the level of risk appropriate for the Company and the steps needed to manage those risks effectively. As an example, we may manage commodity price risk by, when appropriate, entering into appropriate hedge agreements with approved counterparties. We believe that our Board of Directors will take an active role in determining the types and levels of hedging activity to be pursued. Together with management's recommendations, our Board of Directors may approve the counterparties with whom we enter into hedge agreements and the commodity levels hedged. The involvement of the full Board of Directors in setting our business strategy is a key part of its overall responsibilities and together with management determines what constitutes an appropriate level of risk for us.

        While the Board of Directors has the ultimate oversight responsibility for the risk management process, other committees of the Board of Directors also have responsibility for risk management activities. In particular, the audit committee focuses on financial risk, including internal controls, and oversees compliance with regulatory requirements. In setting compensation, the compensation committee recommends approval of compensation programs for the officers and other key employees to encourage an appropriate level of risk-taking behavior consistent with our business strategy. In

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determining strategic business decisions, our strategic and finance committee focuses on business and transactional risks.

Compensation Committee Interlocks and Insider Participation

        For the fiscal year ended 2009, none of our then executive officers served as a member of the board of directors or compensation committee of any entity that had one or more of its executive officers serving as a member of our Board of Directors or compensation committee.

Code of Ethics

        Our Code of Business Conduct and Ethics that applies to our directors, officers and employees (including our Chief Executive Officer, Chief Financial Officer, Chief Accounting & Compliance Officer, controller or other persons performing similar functions) is available on our website (www.aventinerei.com) or in print upon written request at no charge. If we amend or grant any waivers under the code that are applicable to our Chief Executive Officer, our Chief Financial Officer, or our Chief Accounting & Compliance Officer and that relate to any element of the SEC's definition of a code of ethics, which we do not anticipate doing, we will promptly post that amendment or waiver on our website, www.aventinerei.com, under "Corporate Governance."

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EXECUTIVE COMPENSATION DISCUSSION AND ANALYSIS

Executive Compensation

Introduction

        This Compensation Discussion and Analysis (1) provides an overview of our compensation policies and programs; (2) explains our compensation objectives, policies and practices with respect to our executive officers; and (3) identifies the elements of compensation for each of the individuals identified in the following table, whom we refer to in this Compensation Discussion and Analysis as our named executive officers ("NEO").

Name
  Principal Position
George T. Henning, Jr.    Former Interim Chief Executive Officer and Chief Financial Officer
Ronald H. Miller   Former President and Chief Executive Officer
Ajay Sabherwal   Former Chief Financial Officer
Daniel R. Trunfio, Jr.    Former Chief Operating Officer

        We no longer employ these executive officers. Other than an employment offer letter with Mr. Trunfio entered into with Mr. Trunfio prior to our emergence from bankruptcy, we had no employment or severance agreements with any executive officer. The terms provided for in Mr. Trunfio's offer letter were what we deemed necessary to recruit this executive and were established through arm's-length negotiations. For information regarding Mr. Trunfio's offer letter, please see "—Consulting Agreement."

        On March 15, 2010 and pursuant to the plan of reorganization and the Confirmation Order, Thomas L. Manuel was appointed to the position of Chief Executive Officer and Chief Operating Officer of the Company and Benjamin J. Borgen was appointed to the position of Senior Vice President, Commodity Risk Management. In addition, on April 15, 2010 we appointed John W. Castle as Chief Financial Officer. See "—Emergence from Bankruptcy—Employment Agreements."

Executive Compensation Program Objectives

        Our compensation programs are designed to achieve the following objectives:

    Attract and retain top management talent;

    Link compensation realized to the achievement of our short-term and long-term financial and strategic goals;

    Align management and stockholder interests by encouraging long-term stockholder value creation;

    Maximize the financial efficiency of the programs from tax, accounting, cash flow and share dilution perspectives; and

    Support important corporate governance principles and comply with best practices.

        On April 7, 2009, the Company and its subsidiaries filed voluntary petitions for reorganization relief under the provisions of Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Therefore in fiscal year 2009, the long-term objectives of our compensation programs were constrained by our Chapter 11 filing in order to conserve cash and maintain the operations and compliance activities of the Company. There were no increases in the base salaries of our executives other than those associated with Mr. George Henning assuming the additional role of Interim Chief Executive Officer and President and Mr. Daniel Trunfio assuming additional responsibilities upon the departure of our

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former Chief Executive Officer and President, Mr. Ronald Miller. In addition, other than the Key Employee Incentive Plan discussed below there were no short or long-term bonus plans initiated in 2009.

        In connection with our emergence from bankruptcy in March 2010, we adopted a new management incentive plan and appointed a new management team, certain of which entered into employment agreements with us and received stock and/or option awards in connection with their appointment, as described below.

        Because the members of our compensation committee were all appointed in March 2010 after our emergence from bankruptcy, the decisions made for fiscal year 2009 were not decisions made by our current compensation committee. Matters acted upon with regard to the new management incentive plan, new equity awards and employment agreements described below reflect our analysis and decisions of our current board and compensation committee. See "—Emergence from Bankruptcy."

Target Competitive Positioning

        Historically our compensation programs have been designed to link pay to performance. Aside from base salaries, all other compensation components have been tied to performance. In the past we positioned target base salaries and total direct compensation opportunities between the 25th percentile and median of our comparator group to recognize that we are smaller than the typical peer company. In the past we structured our programs to provide the appropriate balance between cash and equity compensation, and short-term and long-term incentives, to further the program objectives identified above. However, due to the bankruptcy filing on April 7, 2009 there were no regular annual increases in base salaries awarded and there were no short or long-term incentive plans established for 2009.

        To help insure that certain members of the senior leadership and management team were properly motivated to undertake the substantial efforts that were required of them to complete the necessary negotiations with various creditor constituencies in order to formulate and propose a Chapter 11 plan and to emerge from Chapter 11, the Company adopted the Aventine Renewable Energy, Inc. and Affiliates Key Executive Incentive Plan (the "KEIP"), which was approved by the Bankruptcy Court through an order dated December 15, 2009.

        The KEIP was designed to provide certain senior executives and managers of the Company (collectively, the "Eligible Employees") with appropriate incentives in order to maximize their efforts to aid in the negotiation, formulation, and consummation of the Chapter 11 plan, and to motivate the Eligible Employees to continue effectively managing our operations and minimize expenditures during the Chapter 11 plan process.

        The KEIP was limited to eight employees and a maximum total payout of $346,662, including one named executive officer, Mr. Trunfio, whose maximum bonus under the plan was $117,000. Pursuant to the KEIP, each of the Eligible Employees was entitled to an incentive bonus payment if we met or exceeded certain specified targets relating to cash position, production level, and the date of emergence from bankruptcy. These targets were designed to be challenging, but attainable.

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        Below is a summary of the plan components, the targets and the incentive payments available for meeting each target:

Plan Components
  % Weighting of maximum
incentive bonus
  Target
1. Cash Position   30%   90% or greater of the planned cash position at emergence
2. Production Level   40%   Production level at emergence equal to or above 105% of plan
3. Emergence Date   30%   March 31, 2010

        Unless terminated "without cause," the Eligible Employees were required to be employed by the Company as of the effective date of the Chapter 11 plan or the closing of a sale of substantially all of our assets in order to receive any payments under the KEIP.

        Pursuant to the KEIP, Mr. Trunfio was paid $70,200 and Mr. Brennan was paid $28,013 on April 9, 2010.

Compensation Committee Procedure and the Compensation Consultant

        The compensation committee of the Board is responsible for making recommendations to the Board regarding the nature and amount of compensation for our executive officers and directors. The compensation committee consists of three non-employee directors: Timothy J. Bernlohr (Chair), Eugene I. Davis, and Kurt M. Cellar. The charter of the compensation committee gives the compensation committee the ability to delegate its authority to subcommittees when it deems appropriate and in the interest of the Company. Prior to March 2010, the compensation committee was responsible for determining the nature and the amount of compensation for our executive officers and directors. The compensation committee consisted of three non-employee directors: Wayne D. Kuhn (Chair), Leigh J. Abramson and Arnold M. Nemirow. The compensation committee's prior charter allowed the compensation committee to delegate its authority to subcommittees or the chairman of the compensation committee when it was deemed appropriate and in our interests. The compensation committee did not, however, delegate its authority with respect to NEO compensation.

        Since 2006, the compensation committee has periodically engaged Frederic W. Cook & Co. ("Cook") as its independent compensation consultant. Cook does no work for management without the consent of the compensation committee chair, receives no compensation from us other than for its work in advising the compensation committee, and maintains no other economic relationships with us. While the compensation committee values the advice of its independent consultant, the compensation committee may choose to take a different approach than that recommended by the consultant for various reasons.

        In 2008, Cook performed an updated comprehensive review of our executive compensation program in terms of design and compensation levels. The review included a total direct compensation analysis for eight executive positions; a carried-interest ownership analysis for the five highest paid executives; and aggregate share usage, fair value transfer, and potential dilution analyses. The results of the competitive review and Cook's preliminary recommendations for the 2008 compensation program were presented and discussed at the July 31, 2008 Board meeting. No such review was performed in 2009, nor does the Company expect that such a review will be performed in 2010.

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Input of Executive Officers on Compensation

        On an ongoing basis, during 2009, the compensation committee received input from the Chief Executive Officer on the personal performance achievements of the executives who reported to him. The evaluation of personal performance was made through a "Right Results—Right Way" analysis which each executive completed in conjunction with the Chief Executive Officer. This individual performance assessment determined a portion of the annual compensation for each executive. In addition, the Chief Executive Officer provided input on salary increases, incentive compensation opportunities, and long-term incentive grants for the executives who reported to him, which the compensation committee considered when making executive compensation recommendations to the Board. During 2009, the compensation committee performed its own review of the Chief Executive Officer, and discussed it with the full Board.

        In addition, during 2009, management provided input into our compensation programs by establishing annual plans and budgets. These were then reviewed and approved by the Board, as the performance goals used in our compensation programs are tied to these annual plans and budgets.

Compensation Elements

        Our compensation program historically had the following elements:

    Base salary;

    Annual incentives (cash bonuses);

    Long-term incentives; and

    Benefits and perquisites.

Base Salary

        Prior to the Chapter 11 bankruptcy filing our policy had been to establish base salaries necessary to attract and retain executive level talent and to provide some minimum level of fixed compensation while reserving an incentive compensation component. Our base salaries have been reviewed annually and are generally targeted between the competitive 25th percentile and median, but may deviate from this competitive position based on the scope of the individual's role in the organization, his or her level of experience in the current position and individual performance.

        The compensation committee made a determination early in 2009 that no salary increases for 2009 would be approved at that time but that the matter could be revisited if conditions changed. Ultimately only two increases were approved for Messrs. Henning and Trunfio as Mr. Henning assumed the additional role of Interim Chief Executive Officer and President and Mr. Trunfio assumed additional responsibilities upon the resignation of Mr. Miller, the former Chief Executive Officer and President. Mr. Henning's original compensation terms were established in March 2009 when he assumed the role of Interim Chief Financial Officer to guide the Company through the bankruptcy process.

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        Base salary information for the NEOs was as follows:

Executive
  2009
Starting
Salary
  2010
Salary
 

Ronald H. Miller

    390,000 (1)    

George T. Henning, Jr. 

    300,000 (2)   450,000 (3)

Daniel R. Trunfio, Jr. 

    315,000     390,000 (4)

Ajay Sabherwal

    262,080 (5)    

(1)
Represents Mr. Miller's annualized 2009 salary. Mr. Miller resigned his position effective October 23, 2009.

(2)
Represents Mr. Henning's annualized 2009 salary. Mr. Henning began employment effective March 16, 2009.

(3)
Mr. Henning's salary was increased by the compensation committee effective October 24, 2009 in recognition of additional duties assumed as Interim Chief Executive Officer and President. Mr. Henning resigned his position effective March 15, 2010.

(4)
Mr. Trunfio's salary was increased by the Board effective October 24, 2009 in recognition of additional duties he assumed. Mr. Trunfio resigned his position effective March 19, 2010.

(5)
Represents Mr. Sabherwal's annualized 2009 salary. Mr. Sabherwal resigned his position effective March 13, 2009.

Annual Incentives

        The compensation committee made the determination early in 2009 that no incentive plan would be established for 2009 but that the matter could be revisited if circumstances changed. Ultimately, no incentive plan was implemented for 2009. The Board has, however, adopted the 2010 Equity Incentive Plan discussed in more detail below under "—Emergence from Bankruptcy—2010 Equity Incentive Plan."

Long-Term Incentive Compensation

        The compensation committee made the determination early in 2009 that a long-term incentive program for 2009 would not be established at that time but that this matter could be revisited if circumstances changed. Ultimately, no long-term incentive plan was implemented for 2009. The Board has, however, adopted the 2010 Equity Incentive Plan discussed in more detail below under "—Emergence from Bankruptcy—2010 Equity Incentive Plan."

Benefits and Perquisites

        During 2009, the NEOs participated in the same benefits programs as our other employees, including health and dental insurance programs, group term life insurance, short-term disability coverage, business travel accident insurance, and our tax-qualified 401(k) plan. We had no supplemental retirement plans or pension plans in which NEOs participated. We generally did not provide any executive perquisites. However, we have paid relocation expenses (e.g., moving expenses, temporary living expenses) in connection with hiring new executives. In the case of Mr. Henning we paid his temporary living and transportation expenses and applied a tax gross-up to keep him whole with respect to the reimbursement of these expenses.

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Hiring of Interim Chief Executive Officer, President and Interim Chief Financial Officer

        On March 9, 2009, the Board appointed George T. Henning, Jr. as Interim Chief Financial Officer of the Company. The Board brought Mr. Henning in to assist the Company through the Chapter 11 bankruptcy process and, upon the resignation of Ajay Sabherwal, the former Chief Financial Officer, they appointed him Interim Chief Financial Officer. Pursuant to an offer letter dated March 5, 2009, Mr. Henning initially received an annual base salary of $300,000 and was eligible for a potential annual bonus as the Board may determine. Mr. Henning received the normal Company benefits for which he was eligible and the Company paid all reasonable costs, including temporary living and transportation expenses and taxes thereon, related to his position of Interim Chief Financial Officer. The Board established Mr. Henning's compensation based upon his over 35 years experience in capital-intensive industries and his experience leading companies through the bankruptcy process.

        On October 14, 2009, upon the resignation of Ronald Miller, the former Chief Executive Officer and President, the Board appointed Mr. Henning as Interim Chief Executive Officer and President of the Company, effective October 24, 2009, in addition to his role as Interim Chief Financial Officer. In connection with his additional responsibilities the Board increased his salary to $450,000. Mr. Henning's offer letter did not provide for any special payments upon termination.

Chief Operating Officer Consulting Agreement and Offer Letter

        We also entered into a consulting agreement with Mr. Trunfio, our former Chief Operating Officer, pursuant to which Mr. Trunfio would make himself reasonably available to respond to inquiries and provide guidance with respect to the business and perform such other advisory services for the Company as may be requested. In exchange for these services he was paid a combined fee of $205,000 and expense reimbursement. The arrangement terminated on March 19, 2010. This consulting agreement was intended to supersede our employment offer letter to Mr. Trunfio. Our employment offer letter, dated February 7, 2007, provided for at-will employment. Pursuant to the offer letter, Mr. Trunfio's starting annual base salary was $300,000. Mr. Trunfio also received a signing bonus of $173,764 (intended to provide him $100,000, net of taxes). Mr. Trunfio was eligible for equity grants in accordance with the 2003 Stock Incentive Plan, and was granted an initial $1,000,000 in restricted stock and 200,000 non-qualified stock options on March 19, 2007. These grants were to vest over a five-year period and the options had an exercise price equal to the closing price of our common stock on the grant date. These awards were provided, in part, to make up for benefits that Mr. Trunfio forfeited from his former employer when he left to join us. Pursuant to the offer letter terms, Mr. Trunfio was granted 50,000 non-qualified stock options on March 19, 2008 and March 19, 2009, each with five-year installment vesting and an exercise price equal to the closing price of our stock on the grant date. The letter also provided for Mr. Trunfio's participation in our then effective Long-Term Incentive Plan and in other benefits programs available to our employees and to our senior executive officers.

Emergence from Bankruptcy

        As a result of our emergence from bankruptcy on March 15, 2010, our new Board of Directors established a new compensation committee to oversee the compensation of our NEOs. Our new compensation committee has not yet adopted a formal policy for allocating between long-term and short-term compensation, between cash and non-cash compensation or among the different forms of non-cash compensation. Instead, the compensation committee, after reviewing data that it deems relevant and consulting with the Chief Executive Officer, determines subjectively what it believes to be the appropriate level and mix of the various compensation components. Other than the employment agreement with and equity awards to our Chief Financial Officer, John Castle, which were recommended for approval by the full Board of Directors by the compensation committee, our new management incentive plan and the terms of the employment agreements and equity awards with our new executive officers, as described below, were negotiated and implemented in connection with our

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emergence from bankruptcy, and approved by the full Board of Directors. Subsequent to our appointment of Mr. Castle as Chief Financial Officer no significant compensation decisions have been made by our compensation committee with respect to our executive officers. Our compensation committee, generally speaking, serves in an advisory capacity to recommend for approval compensation-related matters to our full Board.

Termination of the 2003 Stock Incentive Plan

        In accordance with our plan of reorganization, all outstanding stock and option awards made under the 2003 Stock Incentive Plan were cancelled as of the effective date of our plan of reorganization. Additionally, on the effective date of our plan of reorganization all of our then existing shares of our common stock were cancelled. To again align the executives' interests with those of our shareholders, while at the same time providing an incentive for the executives' commitment to our long-term strategic goals, our plan of reorganization provided for the adoption of a new management incentive plan, which was approved on March 15, 2010, as discussed below.

2010 Equity Incentive Plan

        On March 15, 2010, the Board adopted the Aventine Renewable Energy Holdings, Inc. 2010 Equity Incentive Plan to provide a means through which we can attract and retain key personnel and whereby directors, officers, employees, consultants and advisors (and prospective directors, officers, employees, consultants and advisors) can acquire and maintain an equity interest in us, or be paid incentive compensation, thereby strengthening their commitment to our welfare and aligning their interests with those of our stockholders. The Board or the compensation committee will administer the plan, which provides for the following types of awards:

    options to purchase shares of common stock, including both tax-qualified and non-qualified options;

    stock appreciation rights ("SARs"), which provide the participant the right to receive the excess of the fair market value of a specified number of shares of common stock at the time of exercise over the base price of the SAR, generally payable in shares of common stock;

    stock awards, including grants in the form of (i) shares of common stock that are subject to a restriction period, (ii) rights to receive shares of common stock contingent upon the expiration of a restriction period and (iii) shares of common stock that are not subject to a restriction period or performance measures ("Stock Bonus Awards"); and

    performance compensation awards, which provide the participant the right, contingent upon the attainment of specified performance measures within a specified period, to receive shares of common stock, or the cash value thereof, if such performance measures are satisfied or met.

        Employees, directors, consultants, advisors and prospective employees, directors, consultants or advisors of the Company and its affiliates are eligible to receive awards under the 2010 Equity Incentive Plan.

        The Board or a committee of the Board will determine the terms of any awards granted under the 2010 Equity Incentive Plan, including, without limitation, the number of shares subject to an award, vesting criteria, performance conditions, the manner of exercise, and the effect of certain corporate transactions. Unless otherwise provided in an award agreement, awards granted under the plan generally vest, or the restrictions applicable to the awards generally lapse, on the third anniversary of the date of grant. In the event of a "Change in Control" (as defined in the plan), the Board or committee may provide for the acceleration of the vesting, lapse of restrictions, or performance periods with respect to all or any portion of outstanding awards. With respect to awards of stock options, unless otherwise provided in an award agreement, unvested options expire upon termination of employment

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or service of the participant for any reason, and the vested options remain exercisable for (i) one year following termination of employment or service by reason of a participant's death or disability, but not later than the expiration of the term of the options or (ii) 90 days following termination of employment or service for any reason other than the participant's death or disability, and termination for "Cause" (as defined in the plan), but not later than the expiration of the term of the options, and (iii) both unvested and vested options expire upon the termination of the participant's employment or service by the Company for Cause.

        The aggregate number of shares of common stock reserved for issuance pursuant to the 2010 Equity Incentive Plan is 855,000, subject to certain customary adjustment provisions. The plan expires, and no new awards may be granted after March 15, 2020.

Employment Agreements

        On March 15, 2010 and pursuant to the plan of reorganization and the Confirmation Order, Thomas L. Manuel was appointed to the position of Chief Executive Officer and Chief Operating Officer of the Company and Benjamin J. Borgen was appointed to the position of Senior Vice President, Commodity Risk Management. In addition, on April 15, 2010 we appointed John W. Castle as Chief Financial Officer.

        Thomas L. Manuel    On March 15, 2010, the Company and Mr. Manuel, our Chief Executive Officer and Chief Operating Officer, entered into an employment agreement (the "Manuel Employment Agreement") with a term expiring on December 31, 2012. The terms of the Manuel Employment Agreement provide for, among other things, (i) a base annual salary of $500,000, (ii) a signing bonus of $500,000, (iii) a guaranteed minimum 2010 bonus of $250,000, and after 2010, an annual bonus of at least 125% of Mr. Manuel's base salary, in each case based on reasonably attainable goals as determined by the Board or the compensation committee of the Board after consultation with Mr. Manuel.

        In addition, pursuant to the Manuel Employment Agreement, Mr. Manuel was awarded options to purchase 128,250 shares of common stock with an exercise price at the fair market value on March 15, 2010 of $45.60, as determined by the Board. The options vest 25% on the date of grant, 25% on each of the first two anniversaries of the grant date and 25% on December 31, 2012. The options will expire on the 10 year anniversary of the date of grant. Mr. Manuel was also awarded 42,750 shares of restricted stock ("Restricted Stock") vesting 50% on the date of grant and 50% on the first anniversary of the grant date. In addition, Mr. Manuel was awarded 128,250 restricted stock units ("RSU"), with 85,500 of the RSUs vesting 25% on the date of grant, 25% on each of the first two anniversaries of the date of grant and 25% on December 31, 2012 and the remaining 42,750 RSUs vesting 50% on the second anniversary date of the grant and 50% on December 31, 2012. The options, Restricted Stock and RSUs awarded to Mr. Manuel pursuant to the Manuel Employment Agreement will vest immediately in the event of a "Change of Control" of the Company or termination of his employment by the Company without "Cause" or resignation for "Good Reason."

        For purposes of the Manuel Employment Agreement, a Change of Control means the occurrence of any of the following events:

    any person, other than an exempt person (which includes the Company and its subsidiaries and employee benefit plans), becoming a beneficial owner of 50% or more of the shares of common stock or equity interests or voting stock or equity interests of the Company then outstanding;

    the consummation of a reorganization, merger or consolidation in which existing Company stockholders or members own less than 50% of the equity of the resulting company;

    the consummation of the sale or other disposition of all or substantially all of the assets of the Company; or

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    during any 12-month period and provided no other corporation is a majority shareholder of the Company, individuals who on the effective date of our plan of reorganization, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority thereof, provided that any person becoming a director subsequent to the effective date of our plan of reorganization, whose election or nomination for election was approved by a vote of at least a majority of the directors comprising the Incumbent Board shall be considered a member of the Incumbent Board.

        The Manuel Employment Agreement defines Cause as:

    Mr. Manuel's willful misconduct or gross negligence of a material nature in the performance of his duties;

    Mr. Manuel's being convicted of, or pleading guilty or nolo contendere to a felony (other than a traffic violation);

    Mr. Manuel's willful theft or embezzlement from the Company or our affiliates;

    Mr. Manuel's willful and substantial failure to perform his duties or any other material breach of any material provision of the Manuel Employment Agreement, which is not cured (if curable) by Mr. Manuel within 30 days following his receipt of written notice thereof.

        For purposes of the Manuel Employment Agreement, Mr. Manuel has Good Reason to terminate his employment if, without Mr. Manuel's written consent, any of the following events occurs that are not cured by the Company within 30 days of written notice specifying the occurrence of such Good Reason event, which notice shall be given by Mr. Manuel to the Company within 90 days after the occurrence of the Good Reason event:

    a material diminution in Mr. Manuel's then authority, duties or responsibilities;

    a material diminution in Mr. Manuel's reporting requirements such that Mr. Manuel is no longer reporting to the Board;

    a material diminution in Mr. Manuel's base salary;

    a relocation of Mr. Manuel's principal business location to a location outside of Dallas, Texas; or

    any material breach of the Manuel Employment Agreement by the Company.

        Upon termination without Cause or for Good Reason, Mr. Manuel is entitled to receive (i) accrued but unpaid salary, (ii) a pro-rata bonus for the year of termination and (iii) a lump sum payment equal to the sum of his base salary and bonus for the balance of the term of the agreement and (iv) the costs of continued health benefits for a period of 18 months. The Manuel Employment Agreement also restricts Mr. Manuel from (i) competing with the Company for 12 months following termination, (ii) soliciting any of the Company's current employees for 12 months following termination and (iii) disparaging the Company for three years following termination.

        John W. Castle    On May 5, 2010, the Company and Mr. Castle entered into an employment agreement (the "Castle Employment Agreement") with a term beginning on May 5, 2010, and expiring on December 31, 2012. The terms of the Castle Employment Agreement provide for, among other things, (i) a base annual salary of $350,000, (ii) a guaranteed minimum 2010 bonus of $350,000, and after 2010, an annual bonus with a target of at least 100% of Mr. Castle's base salary and an opportunity to earn an incentive bonus of up to another 100% of his base salary each year, in each case based on attainment of performance metrics as determined by the Chief Executive Officer of the Company and approved by the Board or the compensation committee of the Board.

        In addition, pursuant to the Castle Employment Agreement, Mr. Castle was awarded options to purchase 100,000 shares of common stock of the Company with an exercise price equal to the per share

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fair market value of the common stock on May 5, 2010 of $43.75, as determined by the Board, and 25,000 shares of Restricted Stock. 50% of the options and 50% of the Restricted Stock will vest in three equal installments on each of the first two anniversaries of May 5, 2010, and December 31, 2012, subject to Mr. Castle's continuing employment with the Company. 50% of the options and 50% of the Restricted Stock will vest subject to the attainment of reasonable performance criteria to be determined by the Board. The options will expire on the 10 year anniversary of May 5, 2010 (the "Option Term"). Notwithstanding the foregoing, in the event of (i) a Change of Control (which has the same definition as the one found in the Manuel Employment Agreement) of the Company, 100% of the Restricted Stock and options will vest, and the options will remain exercisable for the remainder of the Option Term or (ii) a termination of Mr. Castle's employment by the Company without Cause (which has the same definition as the one found in the Manuel Employment Agreement), or Mr. Castle's resignation with Good Reason (which has substantially the same definition as the one found in the Manuel Employment Agreement), 100% of the Restricted Stock and options will vest, and the options will remain exercisable for a period following the date of termination of (x) 90 days following a termination by Mr. Castle for Good Reason and (y) 12 months following a termination by the Company without Cause. Any vested options held by Mr. Castle as of his termination will remain exercisable for the applicable periods delineated in the Castle Employment Agreement.

        Upon termination without Cause or for Good Reason, Mr. Castle is entitled to receive (i) any accrued but unpaid base salary, (ii) any earned but unpaid bonus, (iii) reimbursement for any business expenses, (iv) payment for his accrued but unused vacation, (v) vested accrued benefits to which Mr. Castle is entitled under the Company's employee benefit plans and programs applicable to Mr. Castle and (vi) subject to Mr. Castle's signing a general release of claims in the form attached to the Castle Employment Agreement (a) a pro-rata bonus for the year of termination, (b) during the contract term, a lump sum payment equal to the sum of his base salary and bonus and (c) the costs of continued health benefits for a period of 12 months. The Castle Employment Agreement also restricts Mr. Castle from (i) competing with the Company for 12 months following termination, (ii) soliciting any of the Company's current employees for 12 months following termination and (iii) disparaging the Company for three years following termination.

        Benjamin J. Borgen    On March 15, 2010, the Company and Mr. Borgen, our Senior Vice President, Commodity Risk Management, entered into an employment agreement (the "Borgen Employment Agreement") with a term expiring on December 31, 2012. The terms of the Borgen Employment Agreement provide for, among other things, (i) a base annual salary of $400,000, (ii) an inducement bonus of $120,000, and after 2010, an annual bonus of at least 100% of Mr. Borgen's base salary, and the opportunity to earn an incentive bonus of up to another 100% of his base salary, in each case based on attainment of performance metrics as determined by the Chief Executive Officer of the Company and approved by the Board or the compensation committee.

        In addition, pursuant to the Borgen Employment Agreement, Mr. Borgen was awarded options to purchase 51,300 shares of common stock of the Company with an exercise price at the fair market value on March 15, 2010 of $45.60, as determined by the Board, and 55,576 shares of Restricted Stock, under substantially the same terms as Mr. Castle.

        Upon termination without Cause or for Good Reason, Mr. Borgen is entitled to receive substantially the same benefits as Mr. Castle. The Borgen Employment Agreement also contains restrictions substantially similar to the Castle Employment Agreement.

Accounting Treatment of Awards

        We account for stock-based employee compensation using the fair value based method of accounting described in ASC 718. We record the cost of awards with service conditions (i.e., service-vesting stock options) based on the grant-date fair value of the award. The cost of the awards is

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recognized over the period during which an employee is required to provide service in exchange for the award (i.e., the vesting period). In the event of certain terminations of employment (resignation, termination without cause, etc.), no further compensation cost is recognized and the remaining unvested stock grant is cancelled. We record the cost of awards with performance conditions (i.e., performance-shares) based on per-share grant-date fair value, with the ultimate expense based on the number of shares that are actually earned. This expense is accrued based on our expectation of performance results as of each reporting date, and is being amortized over the performance period.

Summary Compensation Table

        The following table sets forth the total compensation for the Company's NEOs for the years ended December 31, 2009, 2008 and 2007.

Name and Principal Position
  Year   Salary
($)
  Bonus
($)
  Stock
Awards
($)(6)(8)
  Option
Awards
($)(6)(8)
  Non-Equity
Incentive Plan
Compensation
($)(7)
  All Other
Compensations
($)(9)
  Total  
            (a)
  (b)
  (c)
  (d)
  (e)
  (f)
  (g)
  (i)
  (j)
 

George Henning, Jr. 

    2009   $ 271,154 (3)                 $ 58,082   $ 329,236  
 

Former Interim

                                                 
 

CEO & CFO

                                                 

Ronald H. Miller

   
2009
   
373,875

(4)
       
   
   
   
14,700
   
388,575
 
 

Former President &

    2008     383,654             513,480     51,371     24,415     972,920  
 

CEO

    2007     353,846                 31,245     26,992     412,083  

Ajay Sabherwal

   
2009
   
80,673

(5)
 
   
   
   
   
4,840
   
85,513
 
 

Former CFO

    2008     257,815             342,320     22,572     21,170     643,877  
 

    2007     245,654                 15,184     21,781     282,619  

Daniel R. Trunfio, Jr. 

   
2009
   
341,538
   
   
   
5,150
   
   
19,057
   
365,745
 
 

Former COO

    2008     308,654         1,000,000     272,870     27,023     83,762     1,692,309  
 

    2007     230,769 (1)   173,764 (2)       1,853,000     14,264     80,344     2,352,141  

(1)
Mr. Trunfio began employment on March 19, 2007 and his compensation for 2007 is for a partial year. Mr. Trunfio resigned his position effective March 19, 2010.

(2)
Represents Mr. Trunfio's signing bonus.

(3)
Mr. Henning began employment on March 16, 2009 as the Company's Interim Chief Financial Officer. Effective October 24, 2009, Mr. Henning became the Company's Interim Chief Executive Officer and President, while retaining his duties as Interim Chief Financial Officer. Mr. Henning resigned his position effective March 15, 2010.

(4)
Mr. Miller resigned his position effective October 23, 2009.

(5)
Mr. Sabherwal resigned his position effective March 16, 2009.

(6)
The value shown under "Stock Awards" and "Option Awards" in the table above represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. The assumptions and methodology used to determine such amounts are set forth in Note 23 of our 2009 annual financial statements.

(7)
No bonus plan was in place for 2009. For additional information regarding the plan, see "Compensation Discussion and Analysis—Compensation Elements—Annual Incentives."

(8)
In accordance with the plan of reorganization and the Confirmation Order, all outstanding stock and option awards made under the 2003 Stock Incentive Plan were cancelled as of the effective date of our plan of reorganization.

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(9)
All Other Compensation for 2009 consisted of:

Executive
  401(k)
Company
Matching
  Tax Gross-up   Relocation
Expenses
  2009 Total  

Ronald H. Miller

  $ 14,7000           $ 14,700  

Daniel R. Trunfio, Jr. 

    14,700         4,357     19,057  

Ajay Sabherwal

    4,840             4,840  

George T. Henning, Jr. 

        17,105     40,977     58,082  

2009 Grants of Plan Based Awards

        The following table sets forth new grants of plan-based awards and opportunities for awards under incentive plans in 2009:

Name
  Grant
Date
  All Other
Stock
Awards:
Number of
Securities
Underlying
Options
  Exercise or
Base Price
of Option
Awards
($/sh)
  Grant Date
Fair Value
of Option
Awards
 

Daniel R. Trunfio, Jr. 

    3/19/2009     50,000   $ 0.18 (1) $ 5,150  

(1)
Grant date fair value of stock options was calculated in accordance with ASC 718 using a form of the Black-Scholes option pricing model and the following assumptions: $0.18 current share price and exercise price, 58% volatility, 0% dividend yield, 6.5 year expected term, and 4.57% risk free interest rate. These options would have become exercisable in equal annual installments on the first five anniversaries of the grant date, or earlier upon a "Change in Control," as defined in the plan. These options were granted on the anniversary of Mr. Trunfio's date of hire, and would have had an exercise price which is the closing price of our stock on that date. This option award, in combination with an initial restricted stock award, and other option awards made to Mr. Trunfio pursuant to the terms of his offer letter, was provided, in part, to make up for benefits that he forfeited from his former employer when he left to join us in March 2007. In accordance with the plan of reorganization and the Confirmation Order, all outstanding stock and option awards made under the 2003 Stock Incentive Plan were cancelled as of the effective date of our plan of reorganization.

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2009 Outstanding Equity Awards at Fiscal Year-End

        The following table sets forth the option and stock awards outstanding for our NEOs as of December 31, 2009:

 
  Option Awards   Stock Awards  
Name
  Number of
Securities
Underlying
Unexercised
Options
Exercisable
(#)
  Number of
Securities
Underlying
Unexercised
Option
Unexercisable
(#)
  Option
Exercise
Price
($)
  Option
Expiration
Date
  Number
of Shares
or Stock
Units
That
Have Not
Vested
(#)
  Market
Value of
Shares or
Stock
Units
That
Have Not
Vested
($)
  Equity
Incentive
Plan
Awards:
Number
of
Unearned
Shares,
Units or
Other
Rights
that Have
Not
Vested
(#)
  Equity
Incentive
Plan
Awards:
Market
Value or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights
That
Have Not
Vested
(#)
 

Ronald H. Miller

    510,203       $ 0.232     6/17/2013 (1)     $          

    260,007         2.918     9/6/2015 (1)                

Daniel R. Trunfio, Jr. 

   
80,000
   
120,000
   
15.260
   
3/19/2017

(1)
 
   
   
   
 

    6,000     24,000     7.050     2/28/2018 (1)                

    10,000     40,000     4.800     3/19/2018 (1)                

        50,000     0.18     3/19/2009 (1)                

                    39,319 (2)   14,548 (2)        

                            7,250 (3)   2,683  

                            7,250 (4)   2,683  

(1)
These stock options had 10 year terms and would have vested in equal annual installments on the first five anniversaries of the grant date. The vesting schedules for Mr. Trunfio's unvested awards are outlined below:

Name
  # of Options   Vesting Schedule
Daniel R. Trunfio, Jr.      120,000   40,000 options would have vested on each of 3/19/10, 3/19/11, and 3/19/12
Daniel R. Trunfio, Jr.      24,000   6,000 options would have vested on each of 2/28/10, 2/28/11, 2/28/12, 2/28/13
Daniel R. Trunfio, Jr.      40,000   10,000 options would have vested on each of 3/19/10, 3/19/11, 3/19/12, 3/19/13
Daniel R. Trunfio, Jr.      50,000   10,000 options would have vested on each of 3/19/10, 3/19/11, 3/19/12, 3/19/13, 3/19/14
(2)
Mr. Trunfio's restricted shares would have vested in five equal annual installments starting one year from the date of grant of 3/19/07.

(3)
Represents the target number of performance shares that were outstanding under the 2007-2009 performance cycle. The payout value of these shares was based upon the closing market price of our common stock on December 31, 2009, which was $0.37. At December 31, 2009, we did not estimate that any amount will ultimately be paid out under this plan. In accordance with the plan of reorganization and the Confirmation Order, all outstanding stock and option awards made under the 2003 Stock Incentive Plan were cancelled as of the effective date of our plan of reorganization.

(4)
Represents the target number of performance shares that were outstanding under the 2007-2010 performance cycle. The payout value of these shares was based upon the closing market price of our common stock on December 31, 2009, which was $0.37. At December 31, 2009, we did not estimate that any amount will ultimately be paid out under this plan. In accordance with the plan of reorganization and the Confirmation Order, all outstanding stock and option awards made under the 2003 Stock Incentive Plan were cancelled as of the effective date of our plan of reorganization.

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2009 Option Exercises and Stock Vested

        The following table sets forth the stock options exercised for our NEOs for the year ended December 31, 2009:

 
  Option Awards   Stock Awards  
Name
  Number of
Shares
Acquired on
Exercise
(#)
  Value Realized
on Exercise
($)
  Number of
Shares Equal on
Vesting
(#)
  Value Realized
on Vesting
($)
 

Ronald H. Miller

    85,000   $ 10,252     0   $ 0  

Daniel R. Trunfio, Jr. 

    0     0     13,106     2,359  

Pension Benefits and Non-Qualified Deferred Compensation

        We do not maintain any pension benefit plans or nonqualified deferred compensation plans for our salaried employees.

Potential Payments Upon Termination or Change in Control

        The table below reflects the amount of compensation to each of the NEOs in the event of a termination related to a change in control, as a result of the accelerated vesting of unvested stock options, restricted shares, and performance shares. The amounts shown assume termination was effective December 31, 2009 and assume a share price of $0.37, our closing share price on December 31, 2009, the last trading day of the calendar year.

NEO
  Accelerated Vesting of Unvested
Equity Compensation*
 

Daniel R. Trunfio, Jr. 

  $ 29,413  

*
Represents the intrinsic value of unvested stock options, unvested restricted shares, and the value of the target number of performance shares granted in 2007 and 2008, as of December 31, 2009, based on a share price of $0.37, our closing price on December 31, 2009.

        Upon termination with cause, all options would have been immediately forfeited. Upon termination due to death or disability, vested options would have remained exercisable for the earlier of one year or their original expiration date, and unvested options would have been forfeited. For all other terminations, vested options would have remained exercisable for the earlier of 90 days or their original expiration date unless the employee had been granted a Board "approved retirement" in which case they would have remained exercisable for two years, and unvested options will be forfeited.

        In the event of termination due to death, disability, or approved retirement, or in the event of a change in control of the Company, vesting of Mr. Trunfio's unvested restricted shares would have accelerated.

        In the event of termination, Mr. Henning would have received no additional benefits beyond those accorded to all employees relative to unused earned vacation and reimbursement of ordinary business expenses incurred to the date of termination.

        There were no employment agreements with Messrs. Miller and Sabherwal providing for termination benefits beyond those accorded to all employees.

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        Upon his resignation, Mr. Trunfio received an aggregate amount of $38,062.50, which represented accrued vacation. Upon his resignation, Mr. Henning received an aggregate amount of $13,846.40, which represented accrued vacation.

Director Compensation

        Our compensation program prior to emergence from bankruptcy for non-employee directors consisted of:

Cash Compensation

    $35,000 annual cash retainer, payable in equal quarterly installments;

    Additional $65,000 annual retainer to the Chairman of the Board;

    Additional committee chair retainers of $10,000 per year for the chair of the audit committee and $5,000 for other committee chairs;

    $1,500 per Board meeting attended ($750 for telephonic meetings); and

    $750 per committee meeting attended, either in person or via phone.

Equity Compensation

    Annual grants totaling $35,000 in RSUs. These RSUs vest after one year.

    One-time initial grant to newly elected directors of $75,000 in RSUs, subject to three year vesting. The annual grant of $35,000 will not be made in the year of initial election.

    After vesting, RSUs must be held for the duration of a director's Board service, and they will only be converted into shares after retirement or other termination.

        The following table sets forth certain information regarding the compensation earned by or awarded to each non-employee director who served on the Board in 2009:

Name
  Fees Earned or
Paid in Cash
($)
  Stock Awards
($)(3)
  Total
Compensation
($)
 

Bobby Latham

    118,750         118,750  

Farokh Hakimi

    69,000         69,000  

Arnold Nemirow

    65,750 (2)       65,750  

Wayne Kuhn

    65,500         65,500  

Leigh Abramson(1)

    64,750         64,750  

Richard Derbes

    56,750         56,750  

Michael Hoffman(1)

    50,750         50,750  

Theodore Butz

    56,750         56,750  

(1)
Cash fees paid to Messrs. Abramson and Hoffman are paid directly to Metalmark Capital LLC.

(2)
Mr. Nemirow was paid $7,761 resulting from the filing of a convenience claim of $22,173.

(3)
Represents the aggregate fair value of stock awards made in 2009 calculated in accordance with ASC 718, Compensation—Stock with respect to fiscal 2009 for restricted stock and RSU awards, disregarding estimated forfeitures related to service-based vesting conditions. No shares of restricted stock were granted to directors in fiscal 2009. In accordance with the plan of reorganization and the Confirmation Order, all outstanding

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    stock and option awards made under the 2003 Stock Incentive Plan were cancelled as of the effective date of our plan of reorganization.

    The aggregate number of unvested shares of restricted stock and RSUs outstanding as of December 31, 2009 for each director was as follows: Abramson—0 shares, Butz—12,658 shares, Derbes—0 shares, Hakimi—0 shares, Hoffman—0 shares, Kuhn—0 shares, Latham—0 shares, and Nemirow—1,405 shares.

    In accordance with the plan of reorganization and the Confirmation Order, all outstanding stock and option awards made under the 2003 Stock Incentive Plan were cancelled as of the effective date of our plan of reorganization.

        On March 15, 2010, our prior director compensation plan terminated and the Board adopted the current director compensation plan. Pursuant to the current director compensation plan, each director, with the exception of the Chief Executive Officer, will receive a $50,000 annual cash retainer, payable in equal quarterly installments. The Chairman of the Board will receive an additional $25,000 annual retainer. The audit committee chairman will receive an additional $10,000 annual cash retainer and all other committee chairs will receive an additional $5,000 annual cash retainer. Each director, with the exception of the Chief Executive Officer, will receive $1,500 per Board meeting attended in person and $750 for telephonic meetings. Each director, with the exception of the Chief Executive Officer, will receive $750 per committee meeting attended, whether in person or telephonic. Each director, with the exception of the Chief Executive Officer, will receive an annual grant at the beginning of each year in the amount of $35,000 in restricted stock units ("Director RSUs"), which will vest one year after the grant date. The Chairman of the Board will receive an additional annual grant at the beginning of each year in the amount of $40,000 in Director RSUs. After vesting, the Director RSUs must be held for the duration of a director's Board service and will only be converted into shares after the director's retirement or other termination.

        Effective as of the effective date of our plan of reorganization, and in accordance with the current director compensation plan, the Chairman of the Board received 1,645 Director RSUs and all other directors received 768 Director RSUs.

Director Ownership Policies

        Our reconstituted Board has not yet established stock ownership requirements. However, the Director RSUs must be held for the duration of each director's Board service.

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PRINCIPAL STOCKHOLDERS

        The following table presents certain information with respect to the beneficial ownership of our shares as of September 7, 2010 by (a) any person or group known to us who beneficially owns more than five percent of our common stock, (b) each of our directors and named executive officers and (c) all directors and executive officers as a group. The percentage of beneficial ownership is based on 7,364,573 shares outstanding, but does not include any actual or estimated future distributions of common stock such holder may receive with respect to the 1,220,530 shares of common stock reserved for issuance pursuant to Section 1145(b) of the Bankruptcy Code under our plan of reorganization, which are to be made on a pro rata basis to holders of our Old Notes and general unsecured claims.

        Except as indicated in footnotes to this table, we believe that the stockholders named in this table have sole voting and investment power with respect to all shares of common stock shown to be beneficially owned by them, based on information provided to us by such stockholders.

Beneficial holders
  Number of
shares
beneficially
held
  Percentage of
beneficial
ownership
 

5% Stockholders:

             
 

Funds managed by Brigade Capital Management, LLC(1)

    1,912,582     26.0 %
 

Funds managed by Whitebox Advisors, LLC(2)

    927,941     12.6 %
 

Senator Global Opportunity Master Fund L.P.(3)

    830,323     11.3 %
 

Funds managed by Brevan Howard Asset Management LLP(4)

    786,071     10.7 %
 

Funds managed by Davidson Kempner Capital Management LLC(5)

    613,828     8.3 %
 

JMB Capital Partners Master Fund, L.P.(6)

    386,137     5.2 %
 

Funds managed by Bay Harbour Management L.C.(7)

    377,854     5.1 %

Directors and Named Executive Officers:

             
 

Thomas L. Manuel(8)(9)

    88,397     *  
 

John W. Castle(8)(10)

    25,000     *  
 

Benjamin J. Borgen(8)(11)

    55,576     *  
 

William J. Brennan(8)

        *  
 

Eugene I. Davis(8)

        *  
 

Timothy J. Bernlohr(8)

        *  
 

Kurt M. Cellar(8)

        *  
 

Douglas Silverman(8)(12)

        *  
 

Carney Hawks(8)

        *  

All directors and executive officers as a group (9 persons)

    168,973     2.3 %

*
Denotes less than 1% beneficially owned.

(1)
Stockholder's address is 399 Park Avenue, 16th Floor, New York, New York 10022. Brigade Leveraged Capital Structures Fund Ltd. owns 1,765,651 shares, SEI Global Master Fund plc owns 17,533 shares, SEI Institutional Investments Trust owns 62,882 shares and SEI Institutional Managed Trust owns 66,516 shares. Donald E. Morgan III, as managing member of Brigade Capital Management, LLC, exercises voting and/or investment control with respect to the shares of the named entities.

(2)
Stockholder's address is c/o Whitebox Advisors, LLC 3033 Excelsior Blvd. Suite 300, Minneapolis, Minnesota 5541-4675. DRE Partners LP owns 251,137 shares, F Cubed Partners LP owns 109,862 shares, Pandora Select Partners, L.P. owns 22,495 shares, Whitebox Credit Arbitrage Partners, L.P. owns 272,513 shares and Whitebox Multi Strategy Partners, L.P. owns 271,934 shares. Andrew J. Redleaf, as managing member of the general partner of the entities named above, exercises voting and/or investment control with respect to the shares of the named entities.

(3)
Stockholder's address is 1330 Avenue of the Americas, 26th Floor, New York, New York 10019. Alexander Klabin and Douglas Silverman, as co-managing members of the investment manager, exercise voting and/or investment control with respect to shares of Senator Global Opportunity Master Fund L.P.

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(4)
Stockholder's address is PO Box 309, Grand Cayman, KY1-1104, Cayman Islands. Brevan Howard Credit Catalysts Master Fund Limited owns 389,312 shares. Brevan Howard Master Fund Limited owns 396,759 shares. DW Investment Management LP, as investment manager, exercises voting and/or investment control with respect to the named entities.

(5)
Stockholder's address is 65 East 55th Street, 19th Floor, New York, New York 10022. Davidson Kempner Distressed Opportunities Fund LP owns 140,577 shares. Thomas L. Kempner, Jr. as executive managing member of DK Group LLC, Stephen M. Dowicz, as managing member of DK Group LLC, Scott E. Davidson, as deputy executive managing member of DK Group LLC, Timothy I. Levart, as managing member and chief operating officer of DK Group LLC, Robert J. Brivio, Jr., as managing member of DK Group LLC, Eric P. Epstein, as managing member of DK Group LLC, Anthony A. Yoseloff, as managing member of DK Group LLC, Avram Z. Friedman, as managing member of DK Group LLC, and Conor Bastable, as managing member of DK Group LLC, exercise voting and/or investment control with respect to the shares of Davidson Kempner Distressed Opportunities Fund LP. Davidson Kempner Distressed Opportunities International owns 300,844 shares. Thomas L. Kempner, Jr. as partner of DK Management Partners LP, Stephen M. Dowicz, as partner of DK Management Partners LP, Scott E. Davidson, as partner of DK Management Partners LP, Timothy I. Levart, as partner and chief operating officer of DK Management Partners LP, Robert J. Brivio, Jr., as partner of DK Management Partners LP, Eric P. Epstein, as partner of DK Management Partners LP, Anthony A. Yoseloff, as partner of DK Management Partners LP, Avram Z. Friedman, as partner of DK Management Partners LP, and Conor Bastable, as partner of DK Management Partners LP, exercise voting and/or investment control with respect to the shares of Davidson Kempner Distressed Opportunities International. Davidson Kempner Institutional Partners, L.P. owns 64,019 shares. Thomas L. Kempner, Jr. as president of Davidson Kempner Advisers Inc., Stephen M. Dowicz, as treasurer of Davidson Kempner Advisers Inc., Scott E. Davidson, as principal of Davidson Kempner Advisers Inc., Timothy I. Levart, as corporate secretary of Davidson Kempner Advisers Inc., Robert J. Brivio, Jr., as principal of Davidson Kempner Advisers Inc., Eric P. Epstein, as principal of Davidson Kempner Advisers Inc., Anthony A. Yoseloff, as principal of Davidson Kempner Advisers Inc., Avram Z. Friedman, as principal of Davidson Kempner Advisers Inc., and Conor Bastable, as principal of Davidson Kempner Advisers Inc., exercise voting and/or investment control with respect to the shares of Davidson Kempner Institutional Partners, L.P. Davidson Kempner International, Ltd. owns 72,582 shares. Thomas L. Kempner, Jr. as executive managing member of Davidson Kempner International Advisors, L.L.C., Stephen M. Dowicz, as managing member of Davidson Kempner International Advisors, L.L.C., Scott E. Davidson, as deputy executive managing member of Davidson Kempner International Advisors, L.L.C., Timothy I. Levart, as managing member and chief operating officer of Davidson Kempner International Advisors, L.L.C., Robert J. Brivio, Jr., as managing member of Davidson Kempner International Advisors, L.L.C., Eric P. Epstein, as managing member of Davidson Kempner International Advisors, L.L.C., Anthony A. Yoseloff, as managing member of Davidson Kempner International Advisors, L.L.C., Avram Z. Friedman, as managing member of Davidson Kempner International Advisors, L.L.C., and Conor Bastable, as managing member of Davidson Kempner International Advisors, L.L.C., exercise voting and/or investment control with respect to the shares of Davidson Kempner International, Ltd. Davidson Kempner Partners owns 31,079 shares. Thomas L. Kempner, Jr. as managing partner of MHD Management Co., Stephen M. Dowicz, as general partner of MHD Management Co., Scott E. Davidson, as deputy managing partner of MHD Management Co., Timothy I. Levart, as general partner and chief operating officer of MHD Management Co., Robert J. Brivio, Jr., as general partner of MHD Management Co., Eric P. Epstein, as general partner of MHD Management Co., Anthony A. Yoseloff, as general partner of MHD Management Co., Avram Z. Friedman, as general partner of MHD Management Co., and Conor Bastable, as general partner of MHD Management Co., exercise voting and/or investment control with respect to the shares of Davidson Kempner Partners. M.H. Davidson & Co. owns 4,727 shares. Thomas L. Kempner, Jr. as executive managing member of M.H. Davidson & Co. GP, L.L.C., Stephen M. Dowicz, as managing member of M.H. Davidson & Co. GP, L.L.C., Scott E. Davidson, as deputy executive managing member of M.H. Davidson & Co. GP, L.L.C., Timothy I. Levart, as managing member and chief operating officer of M.H. Davidson & Co. GP, L.L.C., Robert J. Brivio, Jr., as managing member of M.H. Davidson & Co. GP, L.L.C., Eric Epstein, as managing member of M.H. Davidson & Co. GP, L.L.C., Anthony A. Yoseloff, as managing member of M.H. Davidson & Co. GP, L.L.C., Avram Z. Friedman, as

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    managing member of M.H. Davidson & Co. GP, L.L.C., and Conor Bastable, as managing member of M.H. Davidson & Co. GP, L.L.C., exercise voting and/or investment control with respect to the shares of M.H. Davidson & Co.

(6)
Stockholder's address is 1999 Avenue of the Stars, Suite 2040, Los Angeles, California 90067. Jonathan Brooks, as portfolio manager, and Cyrus Hadidi, as co-portfolio manager, exercise voting and/or investment control with respect to the shares of JMB Capital Partners Master Fund, L.P.

(7)
Stockholder's address is 375 Park Ave., FL 20, New York, New York 10152. BHR Master Fund, Ltd. owns 269,788 shares. BHR OC Master Fund, Ltd. owns 108,066 shares. Steve Van Dyke, as co-managing partner of investment advisor of BHR Master Fund, Ltd., Michael Thompson, as partner of investment advisor of BHR Master Fund, Ltd., and Neil Ramsey, as co-managing partner of investment advisor of BHR Master Fund, Ltd., exercise voting and/or investment control with respect to the shares of the named entities.

(8)
Stockholder's address is c/o Aventine Renewable Energy Holdings, Inc., 120 North Parkway Drive, Pekin, IL 61554.

(9)
Includes options to acquire 32,063 shares of common stock which vested on March 15, 2010, 34,959 shares of Restricted Stock, 50% of which vested on March 15, 2010, and 21,375 RSUs which vested on March 15, 2010.

(10)
Includes 25,000 shares of Restricted Stock, which have been granted but have not been issued by our transfer agent and are not currently outstanding.

(11)
Includes 55,576 shares of Restricted Stock, which have been granted but have not been issued by our transfer agent and are not current