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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

[Mark One]

x      Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the fiscal year ended December 31, 2010.

OR

o         Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the transition period from                          to                         .

Commission file number 001-32922

AVENTINE RENEWABLE ENERGY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

(214) 451-6750

(Registrant’s Telephone Number, including Area Code)

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  YES o  NO x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  YES x  NO o

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  YES o NO x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  YES o  NO o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  YES o  NO x

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2010 was approximately $162,282,880 based upon the closing price of the Common Stock reported for such date on the OTC Bulletin Board.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  YES x  NO o

Indicate the number of shares outstanding of each class of Common Stock, as of the latest practicable date:

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FORM 10-K

YEAR ENDED DECEMBER 31, 2010

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PART I

When we use the terms “Aventine”, “we”, “us”, “our”, and “the Company”, we mean Aventine Renewable Energy Holdings, Inc. and its subsidiaries.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

We make statements under the captions “Business,” “Risk Factors,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in other sections of this Form 10-K that are forward-looking statements. In some cases, you can identify these statements by forward-looking words such as “may,” “might,” “will,” “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “potential” or “continue,” and the negative of these terms and other comparable terminology. These forward-looking statements, which are subject to known and unknown risks, uncertainties and assumptions about us, may include projections of our future financial performance based on our growth strategies and anticipated trends in our business. These statements are only predictions based on our current expectations and projections about future events. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the results, level of activity, performance or achievements expressed or implied by the forward-looking statements. In particular, you should consider the numerous risks and uncertainties outlined in “Risk Factors.”

However, the risks and uncertainties identified in “Risk Factors” are not exhaustive. Other sections of this Form 10-K may include additional factors, which could adversely impact our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and it is not possible for our management to predict all risks and uncertainties, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

Although we believe the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, level of activity, performance or achievements. Moreover, neither we nor any other person assume responsibility for the accuracy or completeness of any of these forward-looking statements. You should not rely upon forward-looking statements as predictions of future events. We are under no duty to update any of these forward-looking statements after the date of this Form 10-K to conform our prior statements to actual results or revised expectations and we do not intend to do so.

Item 1.  Business

General

Aventine, a Delaware corporation organized in 2003, is the successor to businesses engaged in the production and marketing of corn-based fuel-grade ethanol in the United States (the “U.S.”) since 1981.  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 by-products, such as distillers grain, corn gluten meal and feed, corn germ and grain distillers dried yeast, which generate revenue and allow us to help offset a significant portion of our corn costs. Historically, we had also been a large marketer of ethanol, distributing ethanol purchased from other third party producers in addition to our own ethanol production. However, in late 2008 and the first quarter of 2009, we terminated our marketing alliances and substantially reduced our purchase/resale supply operations.

Emergence from Reorganization Proceedings and Related Events

On April 7, 2009 (the “Petition Date”), Aventine Renewable Energy Holdings, Inc. and all of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief under

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Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) with the U.S. Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”).  The Debtors filed their First Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code on January 13, 2010 (as modified, the “Plan”).  The Plan was confirmed by order entered by the Bankruptcy Court on February 24, 2010 (the “Confirmation Order”) and became effective on March 15, 2010 (the “Effective Date”), the date on which the Company emerged from protection under Chapter 11 of the Bankruptcy Code.

In accordance with Accounting Standards Codification (“ASC”) 852, Reorganization (“ASC 852”), we adopted fresh start accounting and adjusted the historical carrying value of our assets and liabilities to their respective fair values at the Effective Date. Simultaneously, the Company determined the fair value of its equity at the Effective Date. The Company selected an accounting convenience date proximate to the Effective Date for purposes of making the aforementioned adjustments to historical carrying values (the “Convenience Date”) because the activity between the Effective Date and the Convenience Date does not result in a material difference in the results. The Company selected a Convenience Date of February 28, 2010. As a result, the Company recorded fresh start accounting adjustments to historical carrying values of assets and liabilities as of February 28, 2010 using market prices, discounted cash flow methodologies based primarily on observable market information and, to a lesser extent, on unobservable market information, and other techniques.

For information on the Company’s emergence from reorganization proceedings and related events see Note 2 of Notes to Consolidated Financial Statements.

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.

The U.S. ethanol industry has experienced rapid growth, increasing from 1.5 billion gallons of production in 1999 to approximately 13.23 billion gallons produced in 2010.  According to the Renewable Fuels Association (the “RFA”), the use of the 13.23 billion gallons of ethanol displaced the need for 445 million barrels of oil to refine into gasoline.  The RFA also reports that the U.S. fuel ethanol industry has approximately 204 operating plants and approximately 13.5 billion gallons of annual production capacity (including idled capacity) for 2011.

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 Energy Independence and Security Act of 2007 (the “EISA”), confirmed by the U.S. Environmental Protection Agency’s (the “EPA”) regulations on the Renewable Fuel Standards (the “RFS”) issued on February 3, 2010 (“RFS2”), sets the upper mandate for grain based ethanol to 15.2 billion gallons by 2015, of which 13.2 million gallons relate to corn based ethanol, and 36.0 million gallons by 2022, of which 15.0 million gallons relate to corn based ethanol.

·                  Economics of ethanol blending. Refiners and blenders increase the profitability of gasoline they sell by blending ethanol in amounts in excess of mandated levels.  The profitability of blending ethanol is further enhanced by the Volumetric Ethanol Excise Tax Credit (the “VEETC”) of $0.45 for each gallon of ethanol blended.  As the need for automotive fuel increases, we believe ethanol will continue to be used to extend fuel supplies.

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·                  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 and for upgrading regular gasoline to premium grades.

·                  Fuel stock extender. According to the Energy Information Administration, domestic petroleum refinery output has increased by approximately 29% from 1980 to 2008, while 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.

Ethanol Production Processes

The production of ethanol from corn can be accomplished through one of two distinct processes: wet milling and dry milling.  According to the RFA, approximately 90% of U.S. ethanol production is at dry mill plants. 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 2.74 gallons of ethanol per bushel of corn while a typical dry mill yields approximately 2.81 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 natural gasoline, to render it unfit for consumption and thus not subject to the alcohol beverage tax.

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 natural gasoline, to render the ethanol unfit for consumption and thus not subject to the alcohol beverage tax.

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Business Overview

Today we derive our revenue primarily from the sale of ethanol produced at our plants.  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.  Gallons of ethanol marketed and distributed were as follows:

Equity Ethanol Production

Our equity production operations generate the substantial majority of our operating income or loss.  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.’’ During 2010, we built 110 million gallon denatured annualized capacity ethanol production facilities at both Mt. Vernon, Indiana, which we refer to as the “Mt. Vernon facility,” and Aurora, Nebraska, which we refer to as the “Aurora West facility.”  Both the Mt. Vernon facility and Aurora West facility were substantially completed by the end of the fourth quarter of 2010; however, in consideration of the winter months, we delayed start-up activities at the Aurora West facility. Additionally, in August 2010 we acquired a 38 million gallon denatured annualized capacity ethanol production facility in Canton, Illinois, which we refer to as the ‘‘Canton facility.”  We expect the Aurora West and Canton facilities to become operational in 2011, subject to weather conditions, commodity prices, and the availability of working capital.

For the year ended December 31, 2010, our facilities had a combined total ethanol production capacity of approximately 317 million gallons annually with corn processing capacity of approximately 119 million bushels per year at capacity.  For each of the years ended December 31, 2009 and 2008, our facilities had a combined total ethanol production capacity of approximately 207 million gallons annually with corn processing capacity of approximately 77 million bushels per year at capacity.  When all of our plants are online and operating at capacity, our expected total ethanol production will be at approximately 465 million gallons annually.

Our plants may operate at a capacity which is less than the stated nameplate 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

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year. We may also occasionally experience either intentional or unplanned outages at our facilities which may negatively impact production and related revenue.

Marketing Alliances

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.  Due to severely declining margins and general liquidity stress due to frozen credit markets during 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.

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. As discussed above 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.

Products

We generated revenue from the following 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.

We experienced a reduction in the 2010 and 2009 percentages of total revenue attributable to ethanol sales, which 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.

By-Products

We generate additional revenue through the sale of by-products, both co-products and bio-products, which result from the ethanol production process.  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

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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, 2010, 2009 and 2008, we recaptured approximately 35.2%, 34.1% and 35.9% of our total corn costs, respectively, from the sale of by-products.

In the wet mill process, the remaining parts of the grain 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 (dried distillers grains with solubles (“DDGS”)) from the dry mill process.  In addition, a wet mill can produce higher value grain distillers dried yeast in order to lower its net corn cost.

Our Illinois wet mill facility produces co-products, such as corn gluten feed (both wet and dry), corn gluten meal, corn distillers with soluble (“CCDS”), and corn germ.  In addition, the fermentation process yields carbon dioxide.  Our dry mill facilities in Pekin, Illinois and Aurora, Nebraska produce co-products such as DDGS, wet distillers grains with soluble and carbon dioxide.  These co-products are sold for various consumer uses into large commodity markets.  Corn gluten feed, corn gluten meal, CCDS and distillers grains 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.

Along with co-products, our Illinois wet mill facility also produces bio-products, Kosher and Chametz freegrain distillers dried yeast, which is processed into a growing variety of products for use in animal and human food and fermentation applications.

Co-products produced by the dry mill process have less value historically than those produced by the wet mill process. In the dry mill process, the principal co-product produced is DDGS, which is sold as a protein used in animal feed.  DDGS recovers a portion of the total cost of the corn, although less than the co-products resulting from the wet mill process.

Customers

The substantial majority of our customer base has purchased ethanol from us for over five years (including our predecessor companies).  In 2010, 2009 and 2008, our ten largest customers accounted for approximately 82%, 66% and 50%, respectively, of our consolidated ethanol sales volume.

In 2010, Buckeye Energy Services, LLC and BioUrja Trading, LLC (“BioUrja”) accounted for 17.0% and 11.0%, respectively, of the Company’s consolidated net sales.  In 2009, BioUrja and Exxon Mobil accounted for 10.5% and 11.1%, respectively, of the Company’s consolidated net sales.  No other customers in 2010 and 2009 represented more than 10% of Aventine’s consolidated net sales.

Pricing and Backlog

Ethanol is generally sold through short-term contracts.  The majority of ethanol sold to customers is based upon index prices.  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.  As of December 31, 2010, we had contracts for delivery of ethanol totaling 29.3 million gallons through September 30, 2011, of which 11.7 million gallons were based on fixed-price contracts and 17.6 million were at spot prices using Platt and OPIS indices.

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Raw Materials and Suppliers

Our principal raw material is #2 yellow corn.  In 2010, 2009 and 2008, we purchased approximately 71.8 million, 74.2 million and 71.4 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. 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.

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 Chicago Board of Trade price as a benchmark.  Corn is delivered to our facilities via truck through local distribution networks and by rail.

Utilities

The production of ethanol requires significant amounts of natural gas.  In an attempt to minimize the effects of the volatility of the price of natural gas, we may take economic hedging positions in this commodity.

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.  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 as our Mt. Vernon facility reaches nameplate capacity and with the start-up of our Aurora West and Canton facilities.  We expect the Aurora West and Canton facilities to become operational in 2011, subject to weather condition, commodity prices and the availability of working capital.

Employees

At December 31, 2010, we had a total of 341 full-time equivalent employees, compared to 302 as of December 31, 2009. Approximately 45% 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 Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industry and Service Workers International Union, Local 7-662 (the “Union”). Our contract with the Union is scheduled to expire on October 31, 2012.

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, 2010, we produced 186.4 million gallons of ethanol and increased our ethanol inventory by 3.6 million gallons for a total sales volume of 184.0 million gallons, including 1.2 million gallons of ethanol sold from non equity production.

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·                  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, including 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, ConocoPhillips, 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 36.2% of our corn cost in the year ended December 31, 2010, 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 27.6% and 22.2% of our total corn costs, respectively, in the year ended December 31, 2010.

·                Experienced and Proven Management Team. Our management team has a combined 75 years of experience in the ethanol production industry. Our Chief Executive Officer, Thomas Manuel, has 40 years experience in managing commodity-related businesses and 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.

Competition

We operate in a highly competitive ethanol marketing and production industry.  The top ten producers, of which we are one, accounted for approximately 46.2%, 47.9% and 46.6% of total industry capacity for the years ended December 31, 2010, 2009 and 2008, respectively.  All of these producers have annual production capacity exceeding 200 million gallons per year.  The largest ethanol producer’s share of domestic capacity increased slightly to 12% in 2010, from 11% in 2009 and 2008.  According to the RFA, the U.S. leads the world in ethanol production with 204 biorefineries in 29 states across the country as of January 2011, with an additional 10 plants either expanding or under construction.

As a result of Valero Energy’s acquisition of ten ethanol plants during 2009, 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.

Historically, the world’s ethanol producers have 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).  However, in recent years, we have begun facing competition from foreign producers.  Brazil is the world’s second largest ethanol producer.  Brazil makes ethanol primarily from sugarcane, a process which has historically been lower in cost than producing ethanol from corn.  Several large companies produce ethanol in Brazil.

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Business and Growth Strategies

We are pursuing the following business and growth strategies:

·                  Opportunistically Add Production Capacity to Enhance Operating Cash Flow. We have identified opportunities to increase our equity production capacity through the development of new production facilities and are continually exploring acquisition opportunities. During 2010, we built 110 million gallon denatured annualized capacity ethanol production facilities at both Mt. Vernon, Indiana and Aurora, Nebraska, which were substantially completed by the end of the fourth quarter of 2010.  Additionally, in August 2010, we acquired the Canton facility. After the completion of these projects, our expected ethanol production capacity will be approximately 465 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.  The original RFS program required 7.5 billion gallons of renewable fuel to be blended into gasoline by 2012. Under the EISA, the RFS program was expanded to increase the volume of renewable fuel required to be blended into transportation fuel from 9.0 billion gallons in 2008 to 36.0 billion gallons by 2022, of which 15.0 billion gallons relates to corn based ethanol.

·                  Entry into new and diversified markets. We are continually negotiating additional sales agreements. We strive to enhance and optimize 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 export opportunities for our ethanol and co-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, Inc., and Archer-Daniels-Midland Company. We are transforming from a seller of ethanol first and a producer second to a producer with focus on risk and logistics management.

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 volume of renewable fuel required to be blended into transportation fuel from 9.0 billion gallons in 2008 to 36.0 billion gallons by 2022, of which 15.0 billion gallons relates to corn based ethanol. 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.

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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. The tax incentives were extended through 2011. We cannot give assurance that the tax incentives will be renewed in 2011 or, if renewed, on what terms they will be renewed. 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, and ultimately the tariff was extended through 2011.

Ethanol imports from 24 countries in Central America and the Caribbean Islands are exempt from this tariff under the Caribbean Basin Initiative (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 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.

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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 and 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 requires 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 facility. 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 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 others 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 December 31, 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.

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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 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 approximately $6.5 million, which would be considerably 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 now, 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. With respect to the investigation of our Nebraska facility, we were required to pay a fine of $40,000. Due to the larger capacity of the Illinois facilities, the fine could possibly be larger.

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 Standard for Hazardous Air Pollutants (“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 passed 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’’ 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

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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 RFS2. 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 RFS2 will apply to domestic and foreign producers and importers of renewable fuel used in the U.S.

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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.

This rule sets the 2010 RFS volume standard at 12.95 billion gallons for 2010, of which 12.0 billion gallons relate to corn based ethanol, and 13.95 gallons for 2011, of which 12.6 billion gallons relate to corn based ethanol. 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 was set at 6.5 million gallons, and the biomass based diesel standard was set at 1.15 billion gallons (combining the 2009 and 2010 standards as proposed). For 2011, the cellulosic standard is set at 6.6 million gallons, and the biomass based diesel standard is set at 1.20 billion gallons.

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.

Where You Can Find Additional Information

Aventine files current, annual and quarterly reports, and other information required by the Exchange Act, with the SEC. You may read and copy any document the company files at the SEC’s public reference room, located at 100 F Street, N.E., Washington, D.C. 20549, U.S.A. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. The Company’s SEC filings are also available to the public from the SEC’s internet site at http://www.sec.gov.

Our public internet site is http://www.aventinerei.com. We will make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and Forms 3, 4, and 5 filed on behalf of directors and executive officers, to the extent we and such persons are required to file such reports, and any amendments to those reports filed or furnished pursuant to the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Also available on our website, and available in print upon request, are our corporate governance guidelines, the charters of our audit, compensation and nominating and corporate governance committees, and a copy of our code of business conduct and ethics that applies to our directors, officers, and employees, including our chief executive officer, principal financial officer, principal accounting officer, controller, or other persons performing similar functions.  Information on our website should not be considered to be part of this annual report on Form 10-K.

Aventine expects to furnish its proxy materials and audited financial statements to security holders subsequent to the filing of this annual report on Form 10-K, and will furnish copies of such materials to the SEC.

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Item 1A.  Risk Factors

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 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 credit facility with PNC Bank National Association (the “Revolving Facility”). On February 28, 2011, the Company amended the Revolving Facility which increased the maximum loan amount from $20.0 million to $30.0 million.  The amendment requires the Company to provide cash as security for all outstanding and undrawn letters of credit but allows the Company to utilize the existing $5.0 million pledged to PNC as part of the cash required to secure the letters of credit.  As of February 28, 2011, the Company had cash secured letters of credit of $10.3 million and $3.6 million in letters of credit secured by the undrawn portion of the Revolving Credit and Security Agreement between the Company and its subsidiaries, as borrowers, and PNC Bank National Association, as lender and agent, dated March 15, 2010 (the “Revolving Credit Agreement”).  Upon the execution of the amendment, the Company moved $3.6 million of the previously pledged $5.0 million of cash as security for the letters of credit.  The Company continues to be subject to all other terms and restrictions contained in the original agreement.

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 the Revolving Facility, will be sufficient to fund our operations.

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 the 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 have significant indebtedness under a term loan facility and the Revolving Facility. Our term loan facility and the Revolving Facility have substantial restrictions and affirmative covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations.

As of December 31, 2010, we had an aggregate of approximately $348.0 million in debt outstanding due to a $200 million term loan facility (the “Term Loan Facility”) with Citibank N.A. (the “Term Loan Agreement”) and our 13% senior secured notes due 2015 (the “Notes”).  In addition, we had availability under the Revolving Facility of approximately $4.1 million as of December 31, 2010 without giving effect to our February 2011 amendment to the Revolving Facility. As a result of our indebtedness, we will use a

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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.  On January 21, 2011, we utilized $164.8 million of our restricted cash to redeem the Notes.

Our indebtedness under the Term Loan Facility and the 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;

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

We may be unable to secure additional financing.

Our ability to arrange, in addition to the Revolving Facility and the Term Loan 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

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

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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. 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. 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 raising 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, or to obtain alternative financing, could materially and adversely affect our business, financial condition, and results of operations.

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

Borrowings under the Revolving Facility and the Term Loan 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.

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 2010, we purchased approximately 71.8 million bushels of corn, which comprised about 72.0% of our total cost of production. 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 the 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 RFS program 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

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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.

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, including at our natural gas-fired corn dry mill plant in Pekin, Illinois and our natural gas-fired corn dry mill plant in Aurora, Nebraska.  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 2001 through December 31, 2010, based on the New York Mercantile Exchange, or NYMEX, daily futures data, has ranged from a low of $1.69 per MMBtu in November 2001 to a high of $18.48 per MMBtu in February 2003. 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 as our Mt. Vernon facility reaches nameplate capacity and with the start-up of our Aurora West and Canton facilities.  We expect the Aurora West and Canton facilities to become operational in 2011, subject to weather condition, commodity prices and the availability of working capital.

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.  At December 31, 2010, we had fixed-priced contracts to sell 11.7 million gallons of ethanol.

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. As a result, our results of operations may be adversely affected during periods in which corn and/or natural gas prices increase.

Our hedging or derivative transactions may be adversely affected by the Dodd-Frank Act.

On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which, among other things, aims to improve transparency and accountability in derivative markets. While the Dodd-Frank Act increases the regulatory authority of the Commodities Futures Trading Commission (the “CFTC”) regarding over-the-counter derivatives, there is uncertainty on several issues related to market clearing, definitions of market participants, reporting, and capital requirements, and many details remain to be addressed in CFTC rulemaking proceedings.  At this time we are unable to predict what effect, if any, these provisions of the Dodd-Frank Act will have on our results of operations or financial condition.

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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 by-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 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.

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.

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.

According to the RFA, domestic ethanol capacity, including capacity under construction, has increased significantly from approximately 1.8 billion gallons per year at January 1999 to 14.0 billion gallons per year at January 2011. Demand for ethanol increased by 22% over 2009, 37% over 2008, 93% over 2007 and 142% over 2006 through increased penetration into new markets and a government mandate; however the production capacity of U.S. ethanol producers continues to exceed demand. In 2010, the production capacity of U.S. ethanol producers exceeded the demand by approximately 0.4%.  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.

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

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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.

Research is currently underway to develop production of biobutanol and similar products 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 p.l.c. (“BP”) and E. I. du Pont de Nemours and Company (“DuPont”). According to the partnership, biobutanol has many advantages over ethanol. Similar developments are also being undertaken with respect to isobutanol. 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 or isobutanol with gasoline is less than that of other biofuels when blended with gasoline; they can be blended at higher concentrations than other biofuels for use in standard vehicles; they are less susceptible to separation when water is present than in pure ethanol gasoline blends; and they are 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 or isobutanol production comes online in the U.S., they 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 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 61.7% and 54.7% of our consolidated net sales for the years ended December 31, 2010 and 2009, respectively. In 2010 and 2009, two customers represented more than 10% of Aventine’s consolidated net sales. In 2008, no customers represented more than 10% of Aventine’s consolidated net sales.

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.

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

As of December 31, 2010, the substantial majority of our income was derived from the sale of ethanol and the related by-products that we produced at our facilities. Our operations may be subject to significant interruption if any of our facilities 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.

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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;

·                  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 recently constructed plants, which could reduce sales and cause us to incur substantial losses.

The Delta-T technology to be utilized at our recently constructed plants 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.

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. 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.

We are contractually obligated to complete certain capacity expansions in Aurora, Nebraska and Mt. 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 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 had not completed the Aurora West facility by September 30, 2010 for each month starting from January 1, 2010 through and

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including September 30, 2010. Beginning on October 1, 2010, we have been subjected to additional penalties of $138,889 per month, and will remain subject to these penalties until the plant (although constructed) is operational or total penalties equaling $5.0 million have been paid by us, whichever comes first. In addition, if we fail to diligently pursue completion of the Aurora West plant or complete the plant by July 31, 2012, such that it is fully operational by such date, the Aurora Co-operative has the option to repurchase the property at $16,500 per acre (subject to adjustment). Pursuant to the Plan, 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 fully operational. 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 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 this obligation, the Indiana Ports Commission may, subject to specified cure rights, take over construction and complete the facility at our expense (among other remedies).

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. 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.  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 2010, the top ten domestic producers accounted for approximately 46.2% 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 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 and would potentially be more willing to sell their ethanol at a lower price than us.

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. 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

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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.

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 2011, (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.

The RFS2, issued on February 3, 2010 by the EPA, may require producers to include alternative technologies in plants under construction, which may increase the cost to complete our Canton facility or acquire new facilities.

The EPA’s recently released RFS2 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. The EPA issued a Direct Final Rule that, among other things, requires all plants that commenced 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 RFS2 requirements. As a result, Phase Two of our Mt. Vernon facility, the Canton facility, or other facilities we may construct or acquire may not be exempt from the 20% lifecycle requirement and could require inclusion of advanced efficient technologies, which could require substantial capital.

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

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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 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 facility. 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 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 December 31, 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

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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 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 approximately $6.5 million, which would be considerably 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 now, 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. With respect to the investigation of our Nebraska facility, we were required to pay a fine of $40,000. Due to the larger capacity of the Illinois facilities, the fine could possibly be larger.

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 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 our Illinois 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 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, 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.

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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, 2010, approximately 45% 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 Union.

On October 29, 2010, the Union ratified a new collective bargaining agreement with Aventine Renewable Energy, Inc. for our hourly production workers in Pekin, Illinois. This new agreement is effective November 1, 2010 and runs through October 31, 2012. The agreement contains provisions, terms and conditions that are customary in collective bargaining agreements of this type, including, among other things, wages, hours, work assignments, management rights, seniority, arbitration and grievance procedures, benefits, vacations, and holidays. The benefit and base wage packages for the currently covered employees remain substantially similar to those in the previous collective bargaining agreement; the currently covered employees also received lump sum annual payments of $750 in November 2010 and will receive an additional lump sum payment of $750 in November 2011. Employees hired after November 1, 2010 will only be eligible for the 401(k) program as their retirement benefit. 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 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 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.

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.

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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.

Item 1B.  Unresolved Staff Comments

None.

Item 2.  Properties

Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 450, Dallas, Texas, 75240.

Facilities

The table below provides an overview of our operational ethanol plants as of December 31, 2010.

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

(2)          The Mt. Vernon lease has an initial expiration date of October 31, 2026, with six five-year extension options.

(3)          The Aurora West facility was substantially completed as of December 31, 2010; however, the Company has not begun start-up operations.

Land for Future Expansion:

We believe that our existing facilities are adequate for our current and reasonably anticipated future needs.

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Item 3.  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.

Item 4.  Removed and Reserved

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for our Common Stock and Holders of Record

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 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 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, 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 March 15, 2011, the last reported sales price of our common stock on the OTCBB was $26.35 per share of common stock. As of February 28, 2011, there were 7,449,046 shares of our common stock outstanding, net of 7,791 shares held in treasury, held by approximately 47 holders of record, based upon the records of our transfer agent, and we estimate that there may be approximately 100 additional holders of record that hold through the facilities of The Depository Trust Company. These numbers do not include stockholders for whom shares are held in a nominee or “street” name. 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.

Dividends

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, pursuant to provisions of the Term Loan Agreement and the Revolving Facility, the Company has limitation on the amount of dividends and distributions it can declare and pay, 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 — Financing — Term Loan Agreement” and “— Revolving Facility.”  We did not declare or pay cash dividends on our common stock during the years ended December 31, 2010 or 2009.

Recent Sales of Unregistered Securities

The following relates to certain issuances of equity securities that have occurred during the period covered by this Annual Report on Form 10-K, and have not been registered under the Securities Act:

On March 15, 2010, we granted the following awards: (i) pursuant to our 2010 Equity Incentive Plan, a total of 179,550 options to certain of our executive officers, with an exercise price of $45.60, none of

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which, as of the filing of this Annual Report on Form 10-K, have been exercised, (ii) pursuant to our 2010 Equity Incentive Plan, restricted stock consisting of an aggregate of 98,326 shares of common stock to certain of our executive officers, (iii) pursuant to our 2010 Equity Incentive Plan, restricted stock units consisting of an aggregate of 128,250 shares of common stock to a certain executive officer, and (iv) pursuant to our Director Compensation Plan, restricted stock units consisting of an aggregate of 4,717 shares of common stock to our directors. We relied on Section 4(2) of the Securities Act to exempt from the registration requirements of the Securities Act the issuance of these awards.

On March 31, 2010, pursuant to our Plan and Confirmation Order, we issued an aggregate of 4,904,980 shares of common stock. The shares were issued and allocated pro rata to the holders of our Old Notes. We received no proceeds from this issuance. Consistent with our Confirmation Order and applicable law, we relied on Section 1145(a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the issuance of the shares. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under a plan of reorganization from registration under Section 5 of the Securities Act.

On April 21, 2010, pursuant to our Plan and Confirmation Order, we issued an aggregate of 71,118 shares of common stock. The shares were issued and allocated pro rata to the holders of general unsecured claims. We received no proceeds from this issuance. Consistent with our Confirmation Order and applicable law, we relied on Section 1145(a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the issuance of the shares.

On May 5, 2010, pursuant to our 2010 Equity Incentive Plan, we granted to a certain executive officer (i) options with an exercise price of $43.75 per share to purchase an aggregate of 100,000 shares of common stock and (ii) restricted stock consisting of an aggregate of 25,000 shares of common stock.  As of the filing of this Annual Report on Form 10-K, none of the options have been exercised. We relied on Section 4(2) of the Securities Act to exempt from the registration requirements of the Securities Act the issuance of these awards.

On June 30, 2010, pursuant to our Plan and Confirmation Order, we commenced a distribution of an aggregate of 599,947 shares of common stock. The shares were issued and allocated pro rata to the holders of our Old Notes. We received no proceeds from this issuance. Consistent with our Confirmation Order and applicable law, we relied on Section 1145(a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the issuance of the shares.

On June 30, 2010, pursuant to our Plan and Confirmation Order, we commenced a distribution of an aggregate of 43,425 shares of common stock. The shares were issued and allocated pro rata to the holders of general unsecured claims. We received no proceeds from this issuance. Consistent with our Confirmation Order and applicable law, we relied on Section 1145(a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the issuance of the shares.

For the period from May 27, 2010 to June 3, 2010, warrants were exercised to purchase 144 shares of common stock at an exercise price of $40.94. We received aggregate gross proceeds of $5,895 from the exercise of such warrants. Consistent with our Confirmation Order and applicable law, we relied on Section 1145(a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the issuance of common stock upon exercise of the warrants.

On September 30, 2010, pursuant to our Plan and Confirmation Order, we commenced a distribution of an aggregate of 32,935 shares of common stock. The shares were issued and allocated pro rata to the holders of our Old Notes. We received no proceeds from this issuance. Consistent with our Confirmation Order and applicable law, we relied on Section 1145(a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the issuance of the shares.

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On September 30, 2010, pursuant to our Plan and Confirmation Order, we commenced a distribution of an aggregate of 10,896 shares of common stock. The shares were issued and allocated pro rata to the holders of general unsecured claims. We received no proceeds from this issuance. Consistent with our Confirmation Order and applicable law, we relied on Section 1145(a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the issuance of the shares.

On October 13, 2010, we granted the following awards: (i) 1,898 shares of common stock to a certain officer, (ii) pursuant to our 2010 Equity Incentive Plan, a total of 46,375 options to certain of our officers, with exercise prices of $45.60 and $27.50, none of which, as of the filing of this Annual Report on Form 10-K, have been exercised, and (iii) restricted stock units to a certain executive officer consisting of an aggregate of 40,000 shares of common stock. We relied on Section 4(2) of the Securities Act to exempt from the registration requirements of the Securities Act the issuance of these awards.

For the period from November 1, 2010 to January 6, 2011, warrants were exercised to purchase 225 shares of common stock at an exercise price of $40.94. We received aggregate gross proceeds of $9,171 from the exercise of such warrants. Consistent with our Confirmation Order and applicable law, we relied on Section 1145(a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the issuance of common stock upon exercise of the warrants.

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Item 6.  Selected Financial Data

The following selected consolidated financial data as of and for the ten months ended December 31, 2010, the two months ended February 28, 2010 and each of the four years ended December 31, 2009, 2008, 2007 and 2006 has been derived from the audited consolidated financial statements of the Company. The following data should be read in conjunction with the consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this Form 10-K.

On March 15, 2010, we emerged from bankruptcy and implemented fresh-start accounting in accordance with ASC 852 using a Convenience Date of February 28, 2010. Therefore, 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. As a result of the application of fresh start accounting, our consolidated financial statements prior to and including February 28, 2010 represent the operations of our pre-reorganization predecessor company and are presented separately from the consolidated financial statements of our post-organization successor company.

We have included EBITDA and Adjusted EBITDA primarily as performance measures because management uses them as key measures of our performance. EBITDA is defined as earnings before interest expense, interest income, income tax expense, and depreciation. EBITDA is not a measure of financial performance under accounting principles generally accepted in the U.S. (“GAAP”) and should not be considered an alternative to net earnings or any other 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 (particularly since, in the latter case, management views EBITDA as a performance measure rather than a liquidity measure). 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).

In order to emphasize the effects of certain income and loss items in our financial statements, we also report a second computation referred to as Adjusted EBITDA, which adjusts EBITDA for certain items. Adjusted EBITDA for the Company is adjusted for (i) loss on early extinguishment of debt, (ii) loss related to auction rate securities, (iii) impairment of plant development costs, (iv) reorganization items, (v) gain due to plan effects, (vi) loss due to the application of fresh start accounting adjustments, (vii) stock-based compensation, (viii) loss on available for sale securities and (ix) gain on resolution of bankruptcy issues. Previously presented calculations have been modified to reflect the current definition of Adjusted EBITDA.

Management believes EBITDA and Adjusted EBITDA are meaningful supplemental measures of operating performance and so highlights trends in our core business that may not otherwise be apparently when relying solely on GAAP financial measures.  We also believe that securities analysts, investors, and other interested parties frequently use EBITDA in the evaluation of companies, many of which present EBITDA when reporting their results.  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

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assist investors in properly assessing the Company’s performance on a year-over-year and quarter-over-quarter basis.  Our management and external users of our financial statements, such as investors, commercial banks, research analysts, and others, use EBITDA and Adjusted EBITDA to assess:

·            the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

·            our operating performance and return capital as compared to those of other companies in our industry, without regard to financing or capital structure; and

·            the feasibility of acquisitions and capital expenditure projects and the overall rate on alternative investment opportunities.

(1)          Total debt includes amounts outstanding under: 1) our secured revolving credit facility, 2) our Revolving Credit Agreement; 3) our senior unsecured notes in 2007 and 2008; 4) our debtor-in-possession debt facility; 5) our previously outstanding Notes and 6) our Term Loan Facility.  The senior unsecured notes are reflected in pre-petition liabilities subject to compromise at December 31, 2009.

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(a)          Interest capitalized during construction was $6.2 million for the ten months ended December 31, 2010, $0 for the two months ended February 28, 2010, $0 for the year ended December 31, 2009, and $26.1 million for the year ended December 31, 2008.

(b)         Contractual interest expense not recorded was $5.0 million and $21.9 million for the two months ended February 28, 2010, and year ended December 31, 2009, respectively.

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with Aventine’s consolidated financial statements and the related notes included elsewhere in this Annual Report on Form 10-K (this “Form 10-K”).

This discussion contains forward-looking statements that involve a number of risks and uncertainties. Words such as “expects,” “anticipates,” “believes,” “estimates,” and other similar expressions or future or conditional verbs such as “will,” “should,” “would,” and “could” are intended to identify such forward-looking statements.  Accordingly, our actual results may differ materially from those expressed or implied in such forward-looking statements due to known or unknown risks and uncertainties that exist in our operations and business environment, including but not limited to those set forth in the section entitled “Risk Factors” and elsewhere in this Form 10-K.

Business Summary

Aventine is a producer and marketer of ethanol.  Through our production facilities, we market and distribute ethanol to many of the leading energy companies in the United States (the “U.S.”).  Our revenues are principally derived from the sale of ethanol and from the sale of co-products and bio-products that we produce as by-products during the production of ethanol at our plants.

Recent Developments

On March 15, 2010, we entered into a Revolving Credit and Security Agreement (the “Revolving Credit Agreement”) with PNC Bank, National Association, as lender and as agent (“PNC”), providing for a $20 million revolving credit facility (the “Revolving Facility”).  The Revolving Credit Agreement was previously amended as of August 6, 2010 and December 22, 2010.  On February 28, 2011, the Company and PNC amended the Revolving Credit Agreement to increase the maximum loan amount to $30.0 million.

2010 Significant Events

Emergence from Reorganization Proceedings and Related Events. On April 7, 2009 (the “Petition Date”), Aventine and all of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions with the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) for relief under Chapter 11 Title 11 of the United States Code (the “Bankruptcy Code”).  The Debtors filed their First Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code on January 13, 2010 (as modified, the “Plan”).  The Plan was confirmed by order entered by the Bankruptcy Court on February 24, 2010 (the “Confirmation Order”) and became effective on March 15, 2010 (the “Effective Date”), the date on which the Company emerged from protection under Chapter 11 of the Bankruptcy Code.  In connection with the Plan, Aventine:

·            appointed a new management team and six new directors to our Board of Directors;

·            issued and sold an aggregate of $105.0 million principal amount of our 13% Senior Secured Notes due 2015 (the “Notes”) and 1,710,000 shares of common stock to holders of our pre-petition notes  (the “Old Notes”) that subscribed to the sale of our Notes;

·            began a pro rata distribution of shares of common stock to holders of our Old Notes and to holders of allowed general unsecured claims, with an initial distribution of 4,904,980 shares to holders of Old Notes and 71,118 shares to holders of allowed general unsecured claims, out of a total of 6,840,000 shares available;

·            entered into the Revolving Facility with PNC;

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·            entered into a warrant agreement with American Stock Transfer & Trust Company, LLC, pursuant to which we issued warrants to purchase an aggregate of 450,000 shares of common stock to holders of equity interests prior to our emergence from bankruptcy;

·            amended and restated our organizational documents and those of our subsidiaries; and

·            adopted a 2010 equity incentive plan providing for the issuance of up to 855,000 shares of common stock, subject to adjustment.

Plant Shutdown.  On June 29, 2010, Aventine temporarily shut down its dry mill plant in Aurora, Nebraska (the “Nebraska facility”) to make some mechanical improvements to the facility.  The shutdown was extended during a period of depressed margins to accelerate a required power outage at both the Nebraska facility and the facility in Aurora Nebraska (the “Aurora West facility”) to complete necessary electrical work for the Aurora West facility which was substantially completed during the fourth quarter of 2010.  We started grinding corn at the Nebraska facility again on August 14, 2010 and the plant achieved full production on August 24, 2010.

Acquisition of Canton, Illinois Facility.  On August 6, 2010, we and New CIE Energy Opco, LLC, d/b/a Riverland Biofuels (“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 facility in Canton, Illinois (the “Canton facility”), and include real property at the plant site as well as surrounding parcels.

Notes Offering.  On August 19, 2010, we issued and sold $50,000,000 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.

Stock Distributions.  On September 30, 2010, including the initial distribution, the Company has made pro rata quarterly distributions, consisting of approximately 5.6 million shares of common stock, to holders of the Old Notes and to holders of allowed general unsecured claims, with approximately 5.5 million shares distributed to holders of the Old Notes and 0.1 million shares to holders of allowed general unsecured claims.  Approximately 1.2 million shares of common stock are reserved for future distributions to these holders. There shares will be distributed as remaining claims are settled in accordance with the Plan. To the extent shares remain after the resolution of these claims, the excess shares will be re-distributed on a pro-rata basis to claim holders who previously received distributions. In addition, during the first quarter of 2011, we expect to commence a pro rata quarterly distribution, consisting of 6,726 shares of common stock, to holders of the Company’s Old Notes and to holders of allowed general unsecured claims. This share distribution was delayed due to the resolution of a bankruptcy claim.

Senior Secured Term Loan Credit Agreement. On December 22, 2010, we entered into a senior secured term loan credit agreement (the ‘‘Term Loan Agreement’’) with Citibank, N.A., as administrative agent and as collateral agent, the lenders party thereto, Citigroup Global Markets Inc. and Jefferies Finance LLC, as joint lead arrangers and joint book-runners, and Citibank, N.A. and Jefferies Finance LLC, as co-syndication agents. Under the Term Loan Agreement, the lenders provided us an aggregate principal amount $200.0 million term loan facility (the ‘‘Term Loan Facility’’).

Expansion.  Following our emergence from bankruptcy, we resumed construction of our Aurora West facility and the facility in Mt. Vernon, Indiana (the “Mt. Vernon facility”). We substantially completed both facilities in the fourth quarter of 2010. We expect the Aurora West facility to become operational in 2011, subject to weather conditions, commodity prices, and the availability of working capital.

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Business Environment

The following discussion includes trends and factors that may affect future operating results.

Commodity Pricing

Our operations are highly dependent on commodity prices, especially prices for ethanol, corn and natural gas.

Ethanol. During 2010, ethanol prices continued to closely follow corn prices. At December 31, 2010, we had future contracts for delivery of ethanol totaling 29.3 million gallons through September 30, 2011, of which 11.7 million gallons were based on fixed-price contracts and 17.6 million were at spot prices using Platt and OPIS indices.

Corn.  Corn prices peaked in June 2008 at around $7.88 per bushel, then fell in late 2008 and early 2009 as commodity prices, and in particular oil prices, declined as a result of a slowing economy brought on by the 2008 financial crisis, lower than expected consumption, including for ethanol and for export as a result of concerns of global recession and reductions in global demand.  During 2010, corn prices rose steadily, with an overall increase in price of 58.7% from January to December.  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 Chicago Board of Trade (“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 December 31, 2010, we had fixed the price of 3.0 million bushels of corn through October 2011 and we had future contracts to purchase 3.9 million bushels of corn.

Natural Gas. 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. The price fluctuation in natural gas prices over 2010, based on the New York Mercantile Exchange daily futures data, has ranged from a high of $7.51 per MMBtu in the beginning of January to a low of $3.18 per MMBtu at the end of October.  Our current natural gas usage is approximately 285,000 MMBtu’s per month.

Supply and Demand

According to the Renewable Fuels Association, the annual corn-based ethanol production capacity of U.S. plants currently in operation and those under construction is approximately 14.0 billion gallons annually (plants currently in operation have a capacity of approximately 13.5 billion gallons annually while plants under construction have an approximate capacity of 0.5 billion gallons annually). This volume of ethanol production exceeds the mandate for renewable biofuel consumption required in 2011 of 13.95 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.

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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 Energy Independence and Security Act of 2007 (“EISA”) was passed which contained a new increased Renewable Fuel Standards (“RFS”). The new RFS requires fuel refiners to use a certain minimum amount of renewable fuels, which will rise from 12.95 billion gallons in 2010, of which 12.0 billion gallons relates to corn based ethanol, to 36.0 billion gallons, of which 15.0 billion gallons relates to corn based ethanol, 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, 2011. This excise tax credit provides incentives for blenders and refiners to blend ethanol with gasoline.

Cancellation of indebtedness income

We recognized income from the cancellation of indebtedness (“COD”) when we emerged from bankruptcy to the extent that debt was 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.

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.

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Financial Statement Overview

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

Fresh-Start Accounting

We emerged from bankruptcy on March 15, 2010. In accordance with Accounting Standards Codification (“ASC”) 852, Reorganization (“ASC 852”), we adopted fresh start accounting and adjusted the historical carrying value of our assets and liabilities to their respective fair values at the Effective Date. Simultaneously, we determined the fair value of our equity at the Effective Date. We selected an accounting convenience date proximate to the Effective Date for purposes of making the aforementioned adjustments to historical carrying values (the “Convenience Date”) because the activity between the Effective Date and the Convenience Date did not result in a material difference in the results. We selected a Convenience Date of February 28, 2010. As a result, we recorded fresh start accounting adjustments to historical carrying values of assets and liabilities as of February 28, 2010 using market prices, discounted cash flow methodologies based primarily on observable market information and, to a lesser extent, on unobservable market information, and other techniques.

In implementing fresh-start accounting, we re-measured our asset values and stated all liabilities, other than deferred taxes, at fair value or at present values of the amounts to be paid using appropriate market interest rates. Our reorganization value was determined based on consideration of numerous factors and various valuation methodologies, including discounted cash flows, believed by management to be representative of our business and industry. Information regarding the determination of the reorganization value and application of fresh start accounting is included in Note 2 of Notes to Consolidated Financial Statements. In addition, under fresh start accounting, accumulated deficit and accumulated other comprehensive income were eliminated.

Under fresh start accounting, our net inventory increased by $2.5 million and property, plant and equipment decreased by $380.0 million, in each case to reflect fair value as of our emergence from bankruptcy. Other assets, which consisted primarily of a long-term deposit for utilities against which we may apply certain natural gas transportation charges, decreased by $4.4 million and were recorded at fair value based on a discounted cash flow calculation using a 13% discount rate and our estimate of purchases of natural gas and the timing of those purchases. Accounts payable increased approximately $1.3 million under fresh start accounting to adjust an off-market coal contract to fair value. We also adjusted long-term debt to its fair value of $105 million, an increase of $6.9 million.

As a result of the $2.5 million upward adjustment to our inventory described above, our cost of sales for the ten months ended December 31, 2010 includes an additional $2.5 million of costs related to the inventory, stepped up to fair value under fresh start accounting, sold during the period. The decrease in property, plant and equipment resulted in lower depreciation expense in the ten months ended December 31, 2010 which is included in cost of goods sold. As a result of the adjustment to the long-term deposit for utilities, we will incur additional amortization cost related to natural gas which will increase cost of goods sold. As a result of the adjustment of accounts payable to record the off-market coal contract at fair value, our coal costs were lower for the ten months ended December 31, 2010 when the contract expired. The increase in long-term debt to its fair value of $105.0 million will result in lower interest expense over the period the debt remains outstanding.

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, the cost of purchasing ethanol from marketing alliance partners and unaffiliated producers, 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

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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.

Our most volatile manufacturing costs are natural gas and corn.  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.  See “Item 1A — Risk Factors” for additional information.

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 accounting principles generally accepted in the U.S. (“GAAP”).

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.

Historically, we had 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 we would take title to the product, assume all risks associated with the purchase and sale of such gallons and be 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 we do not recognize such freight costs in the financial statements.

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,

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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 ASC 815, Derivatives and Hedging (“ASC 815”), for our derivatives.  At December 31, 2010, our futures contracts were not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income.  Such derivative instruments are recorded at fair value, and are included in “Prepaid expenses and other current assets” on our consolidated balance sheets.

Under ASC 815, we are required to evaluate contracts to determine whether such contracts are derivatives.  Certain contracts that meet the 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. We have elected to designate our forward purchases of corn and natural gas and forward sales of ethanol as normal purchases and normal sales under ASC 815.  Accordingly, these contracts are not reflected in the consolidated financial statements until execution.

Income Taxes

Under ASC 740, Income Taxes, 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, debt issuance costs and original issue discount are the primary sources of these temporary differences.  Deferred income taxes also include net operating loss and capital loss carryforwards.  The Company establishes valuation allowances to reduce deferred tax assets to amounts it believes are realizable. These valuation allowances and contingency reserves are adjusted based upon changing facts and circumstances.

Pension and Postretirement Benefit Costs

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.

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Share-Based Compensation Expense

We account for our share-based compensation in accordance with ASC 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 expense recognized is based on the value of the portion of share-based payment awards that is ultimately expected to vest.  We attribute the value of share-based compensation to expense over the periods of requisite service using the straight-line method.

The Company values its share-based payments awards using a form of the Black-Scholes Option Pricing Model (the “Option Pricing Model”).  The determination of fair value of share-based payment awards on the date of grant using the Option Pricing Model is affected by the Company’s 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).   The Company estimated volatility by considering, among other things, the historical volatilities of public companies engaged in similar industries.  Pre-vesting forfeitures are estimated to be 0% due to the nature of the vesting schedules for the limited number of grants made to executives.  The expected option term is calculated using the “simplified” method permitted by ASC 718.  The Company’s options have characteristics significantly different from those of traded options, and changes in the assumptions can materially affect the fair value estimates.

Results of Operations

The following discussion summarizes the significant factors affecting the consolidated operating results of the Company. This discussion should be read in conjunction with our consolidated financial statements and notes to our consolidated financial statements contained herein.

Overview

For the ten months ended December 31, 2010, the two months ended February 28, 2010 and the years ended December 31, 2009 and 2008, we generated net losses of $25.5 million, $266.3 million, $46.3 million and $47.1 million, respectively. The loss in the ten months ended December 31, 2010 is primarily due to selling, general and administrative expenses.  The loss in the two months ended February 28, 2010 is primarily attributable to adjustments of $387.7 million required to report assets and liabilities at fair value under fresh-start accounting and $20.3 million of reorganization items resulting from the Company’s Chapter 11 bankruptcy filing, which were offset by a gain due to plan effects of $136.6 million.  The 2009 net loss of $46.3 million is primarily attributable to $32.4 million in reorganization items. The 2008 net loss of $47.1 million is primarily the 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.

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Total gallons of ethanol marketed and distributed were as follows: