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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

[Mark One]

OR

Commission file number 001-32922

AVENTINE RENEWABLE ENERGY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

(309) 347-9200

(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.  o

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

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, 2009 was approximately $7,303,737 based upon the closing price of the Common Stock reported for such date on the OTC Bulletin Board.

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, 2009

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PART I

Item 1.  Business

General

Aventine Renewable Energy Holdings, Inc. (the “Company,” “Aventine,” “we,” “our,” or “us”) is a producer and marketer of fuel-grade ethanol in the United States (“U.S.”).  We market and distribute ethanol to many of the leading energy and trading companies in the U.S.  We produced 197.5 million gallons and 188.8 million gallons of ethanol in 2009 and 2008, respectively.  Historically, we have also been a large marketer of ethanol, distributing ethanol purchased from other third-party producers in addition to our own ethanol production.  In 2009 and 2008, we distributed 65.7 million gallons and 754.3 million gallons, respectively, of ethanol produced by others.  The decrease in distributed gallons from 2008 to 2009 is attributable to the termination of our marketing alliance and substantial reduction in our purchase/resale supply operations in late 2008 and the first quarter of 2009.  In addition to producing ethanol, our facilities also produce several co-products, such as distillers grain, corn gluten meal and feed, corn germ and brewers’ yeast, which generate incremental revenue and allow us to help offset a significant portion of our corn costs.

We were acquired by the Morgan Stanley Capital Partners funds (“MSCP”) from a subsidiary of The Williams Companies, Inc. on May 30, 2003.  The acquisition was accounted for as a purchase business combination in accordance with Accounting Standards Codification 805, Business Combinations (“ASC 805”).  We are a Delaware corporation organized in 2003, and are the successor to businesses engaged in the production and marketing of ethanol since 1981.  Effective July 5, 2006, we completed an initial public offering of our common stock, $0.001 par value, pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-132860), that was declared effective on June 28, 2006.

Chapter 11 Bankruptcy Proceedings

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 (collectively, the “Bankruptcy Filing”) under Chapter 11 (“Chapter 11”) of Title 11 of the United States Code (the “Bankruptcy Code”) with the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”).  The Chapter 11 cases are being jointly administered by the Bankruptcy Court as Case No. 09-11214 (KG) (collectively, the “Bankruptcy Cases”).  The Debtors specifically are (i) Aventine Renewable Energy Holdings, Inc.; (ii) Aventine Renewable Energy, LLC, a Delaware limited liability company; (iii) Aventine Renewable Energy, Inc., a Delaware corporation; (iv) Aventine Renewable Energy — Mt. Vernon, LLC, a Delaware limited liability company; (v) Aventine Renewable Energy — Aurora West, LLC, a Delaware limited liability company; (vi) Aventine Power, LLC, a Delaware limited liability company, and (vii) Nebraska Energy, LLC, a Kansas limited liability company.

The Debtors are currently operating as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.  In general, as debtors-in-possession, the Debtors are authorized under the Bankruptcy Code to continue to operate as an ongoing business, but may not engage in transactions outside of the ordinary course of business without the approval of the Bankruptcy Court.

On April 7, 2009, certain of the Company’s bondholders entered into a term sheet (the “DIP Term Sheet”) for a $30 million Debtor-in-Possession Credit Facility with the Debtors.  The DIP Term Sheet provides, subject to certain conditions as described in the Debtor-in-Possession Credit Facility Term Sheet filed as Exhibit 10.1 to our Form 8-K filed on April 13, 2009 for a first priority debtor-in-possession

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financing comprised of a term loan facility made available to certain of Aventine’s subsidiaries in a maximum aggregate principal amount of up to $30 million (the “DIP Facility”).  On May 5, 2009, the Bankruptcy Court overruled objections from the Debtors’ pre-petition secured lenders and approved the DIP Facility on a final basis.  Proceeds of the DIP Facility are available to, among other things, (i) fund the working capital and general corporate needs of the Debtors and the costs of the Bankruptcy Cases in accordance with an approved budget, and (ii) provide adequate protection, in accordance with the terms of the DIP Facility, to the pre-petition agent and pre-petition lenders under the Company’s existing credit facilities.  The DIP Facility bears interest at 16.5% per annum.  The maturity date of the DIP Facility is April 6, 2010, or upon the occurrence of certain pre-defined events.  The DIP Facility is secured by a super-priority administrative claim on our assets.

On December 4, 2009, the Debtors filed the Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009 (the “Initial Chapter 11 Plan”) and the Disclosure Statement for the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009.  The Debtors amended the Initial Chapter 11 Plan and on January 13, 2010, the Debtors filed the Debtors’ First Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code dated as of January 13, 2010 (as amended, modified an/or supplemented, the “Plan” or “Plan of Reorganization”) and the Disclosure Statement for Debtors’ First Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code dated January 13, 2010 (as amended, modified and/or supplemented, the “Disclosure Statement”).  A hearing has been scheduled by the Bankruptcy Court for February 24, 2010 to consider confirmation of the Plan.

Although the Debtors filed a Chapter 11 plan that provides for emergence from Chapter 11 some time in the future, there can be no assurance that a Chapter 11 plan will be confirmed by the Bankruptcy Court, or that any such plan will be consummated.  In order to successfully emerge from bankruptcy, the Debtors will need to, among other things, obtain alternative financing to replace the DIP Facility.  The Company has obtained approval of the Disclosure Statement and is pursuing confirmation of the Plan, which includes a backstop lending agreement in connection with the issuance of senior secured notes in the face amount of $105 million.  For further discussion, see “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Going Concern Matters

The ability of the Company to continue as a going concern is dependent upon, among other things, (i) the Company’s ability to comply with the terms and conditions of the DIP Facility; (ii) the ability of the Company to maintain adequate cash on hand; (iii) the ability of the Company to generate cash from operations; (iv) the ability of the Company to obtain confirmation of and to consummate a plan of reorganization under the Bankruptcy Code; (v) the cost and outcome of the reorganization process; (vi) the Company’s ability to obtain alternative financing; and (vii) the Company’s ability to achieve profitability.  Uncertainty as to the outcome of these factors raises substantial doubt about the Company’s ability to continue as a going concern.  The Company is currently evaluating various courses of action to address the issues the Company is facing.  There can be no assurance that any of these efforts will be successful.

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

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We have prepared  the consolidated financial statements in accordance with Accounting Standards Codification 852, Reorganizations (“ASC 852”).  This guidance requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business.  Accordingly, certain expenses (including professional fees), realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in reorganization items on the accompanying Consolidated Statements of Operations.  In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the  Consolidated Balance Sheet at December 31, 2009 in “pre-petition liabilities subject to compromise.”  These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.  For information on the bankruptcy reorganization process, see Note 2 - Chapter 11 Bankruptcy Proceedings.

Available Information

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports are available on our website, at no charge, at www.aventinerei.com, as soon as reasonably practicable after electronic filing or furnishing such information to the U.S. Securities and Exchange Commission (“SEC”).  Also available on our website, or in print upon written request at no charge, 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.  Finally, there is a section on our website covering the status of the Company’s reorganization under Chapter 11 of the Bankruptcy Code.  Information on our website should not be considered to be part of this annual report on Form 10-K.

Industry Overview

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

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

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

The U.S. fuel ethanol industry has experienced rapid growth, increasing from 1.4 billion gallons of production in 1998 to approximately 9.0 billion gallons produced in 2008, the latest year for which production information is available.  According to the Energy Information Administration, LEGC, LLC, the use of that 9.0 billion gallons of ethanol displaced the need for 321.4 million barrels of oil.  The Renewable Fuels Association (“RFA”) reports that  the U.S. fuel ethanol industry has approximately 11.9 billion gallons of operating annual production capacity as of December 2009.

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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 signed into law on December 19, 2007, requires mandated minimum usage of renewable fuels of 12.95 billion gallons in 2010 and 13.95 billion gallons in 2011. The mandated usage of renewable fuels increases to 36 billion gallons in 2022.  The mandate for corn-based ethanol is capped at 15 billion gallons for the years 2015 through 2022.

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

·                  Carryover of Renewable Identification Number credits (“RINS”).  Refiners, importers and blenders (other than oxygen blenders) of gasoline are obligated parties under the Renewable Fuels Standard.  The consumption of ethanol above mandated amounts creates an excess of RINS that  are available to satisfy an obligated party’s blending requirements in the following year.  The obligated parties are allowed to meet their requirement to consume renewable fuels through the accumulation or purchase of excess RINS, instead of from the actual physical purchase of renewable fuels.  From September 1, 2007 through mid 2008, obligated parties blended significantly more ethanol than was required by the mandate as the economics of blending ethanol were quite profitable.  As the blending economics of ethanol became less profitable with the rapid decline in oil prices beginning in the second half of 2008, obligated parties began to apply these excess RINS to meet their obligations which resulted in a significantly reduced demand for ethanol.  For 2009, obligated parties blended approximately the same amount of ethanol that was required by the mandate.  However, the carryover of 2008 RINS into 2009 created an excess of 2009 RINS that will be available to satisfy an obligated party’s blending requirements in 2010.  Our view is that there are approximately 1.50 billion RINS available to satisfy an obligated parties requirement for 2010.  With the 2010 mandate for renewable biofuels at 12 billion gallons, this means that the actual physical ethanol volume that has to be purchased can be as low as 10.50 billion gallons.

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

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

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

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

Ethanol Production Processes

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

Wet Milling

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

The remaining parts of the grain in the wet mill process are processed into a number of different forms of protein used to feed livestock.  The multiple co-products from a wet mill facility generate a higher level of cost recovery from corn than the principal co-product (dried distillers grains with solubles (“DDGS”)) from the dry mill process.  In addition, a wet mill, if properly equipped, can produce a higher value brewers’ yeast in order to lower its net corn cost.  For the years ended December 31, 2009, 2008 and

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2007, we recovered 42.7%, 45.6% and 46.3%, respectively, of our total corn costs related to our wet mill process through our sale of co-products and bio-products.

Dry Milling

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

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

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The following graphic depicts the corn to ethanol conversion process:

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Business Overview

We derive our revenue primarily from the sale of ethanol.  We also derive revenue from the sale of co-products (corn gluten feed and meal, corn germ, condensed corn distillers with solubles (“CCDS”), carbon dioxide, DDGS and wet distillers grains with solubles (“WDGS”)) and bio-products (brewers’ yeast) which are produced as by-products during the production of ethanol 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.  With our own equity production combined with ethanol sourced from third parties, we marketed and distributed 277.5 million, 936.0 million and 690.2 million gallons of ethanol for the years 2009, 2008 and 2007, respectively.  Because of the challenges facing the ethanol industry in general and us in particular, we sharply decreased the number of gallons of ethanol we sold that were produced by others in 2009 by terminating our marketing alliance and significantly reducing our purchase/resale operation.

Equity Ethanol Production

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

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

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

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

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Marketing Alliance Production

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

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

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.

For the years ended December 31, 2008 and 2007, we purchased for resale  249.0 million and 111.5 million gallons of ethanol, respectively, from unaffiliated producers and marketers.  As discussed above under “Marketing Alliance Production” and further discussed under “Item 1 — Business — Marketing Alliances”, we began a program to rationalize our distribution network and reduce our sourcing of ethanol from third parties in late 2008.  Our purchase/resale program was part of this rationalization process.  Accordingly, we only purchased 35.5 million gallons of ethanol for resale from unaffiliated producers and marketers during 2009.

By-Products

We generate additional revenue through the sale of by-products (both co-products and bio-products) that result from the ethanol production process.  These by-products include brewers’ yeast, corn gluten feed and meal, corn germ, CCDS, carbon dioxide, DDGS and WDGS.  The volume of by-products we produce varies with the level of our equity production.  Scheduled maintenance, along with other non-scheduled operational difficulties, may affect the volume of by-products produced.  We may also shift the mix of these

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

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

Products

Ethanol

Our principal product is fuel-grade ethanol, an alcohol which is derived in the U.S. principally from corn.  Ethanol is sold primarily for blending with gasoline to meet mandates for the required consumption and use of biofuels, as an octane enhancer, as an oxygenate additive for the purpose of meeting fuel emission standards and as a fuel extender.  See “Item 1 — Business — Industry Overview.” For the years ended December 31, 2009, 2008 and 2007, ethanol sales represented 81.5%, 92.5% and 91.3%, respectively, of our total revenue.  The reduction in the 2009 percentage of total revenue attributable to ethanol sales is the result of the elimination of the ethanol sales dollars attributable to our marketing alliance and substantial reduction in the ethanol sales dollars attributable to our purchase/resale supply operation from our total revenue numbers for 2009.

Co-Products

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

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Bio-Products

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

Competition

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

A significant development during 2009 was Valero Energy’s acquisition of ten ethanol plants from VeraSun Energy and Renew Energy.  As a result of the acquisitions, the second largest U.S. oil refiner is now a top 10 producer with annual ethanol production capacity of approximately 1 billion gallons.

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

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

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

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

Business Strategies

Our objective is to strengthen and reposition our Company by concentrating on improving our liquidity, competitiveness, operating performance and customer service, and to remain a leading supplier and distributor of ethanol in the U.S.  Towards this end, we are pursuing the following business strategies:

Liquidity Preservation and Balance Sheet Restructuring

As a result of our bankruptcy filing, we have been accelerating our efforts to preserve existing liquidity, and are attempting to raise additional sources of liquidity and capital in conjunction with our proposed Plan of Reorganization.  We have suspended construction of our expansion facilities at both Mt. Vernon, Indiana and Aurora, Nebraska.  We have taken steps to reduce our fixed cost structure by rationalizing and reducing the size and scope of our distribution network.  We have also reduced our workforce, primarily as a result of the termination of our marketing alliance.

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Although we are actively pursuing a number of liquidity alternatives in conjunction with our proposed Plan of Reorganization, there can be no assurance we will be successful or that the Plan, or any other Chapter 11 plan, will be confirmed by the Bankruptcy Court.  For more information see “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital.”

Optimizing Productivity and Infrastructure

We are improving the efficiency and effectiveness of our distribution and logistics assets, and are optimizing our resources to support innovation and future growth.

In light of rapid changes in customer demands that are occurring relative to the distribution and sale of ethanol in the marketplace, we undertook a rationalization of our terminal and distribution system.  As part of this rationalization process, we significantly reduced or eliminated our presence in numerous terminals, resulting in the reduction of fixed transportation commitments to barges and railcars.  These steps have significantly reduced the fixed costs of maintaining our distribution and logistics assets.

Sales and Marketing

We employ direct sales personnel to pursue sales opportunities.  In addition, customer service representatives are available to respond to customer questions and to undertake or resolve any required customer service issues.  Our sales structure forms an integral, critical link in communicating with our customers.  The sales function is coordinated through key senior executives responsible for our sales and marketing efforts.

Marketing Alliances

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

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

Investments

Historically, we had made minority investments in other ethanol producers.  Investments made by the Company in other ethanol producers after May 31, 2003 were recorded at cost, including our investment in Indiana BioEnergy (“IBE”) prior to its acquisition by Green Plains Renewable Energy (“GPRE”).  Our investment in IBE was valued at December 31, 2007 at our initial investment cost of $5.0 million.  On October 15, 2008, IBE merged with GPRE, a publicly held company whose shares are traded on the NASDAQ national market, and our $5.0 million original investment was converted to 365,999 shares of

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GPRE stock.  On October 15, 2008, we recorded a loss of $2.8 million on the exchange and reduced the value of our investment from $5.0 million to $2.2 million, which was the market price of the GPRE shares at that date.  As our investment in GPRE shares is considered an available for sale investment in accordance with Accounting Standards Codification 320, Investments - Debt and Equity Securities (“ASC 320”), we recognized an other than temporary loss of $1.5 million on December 31, 2008.  We made our determination that the loss in GPRE stock was other than temporary, considering our lack of ability and intent to hold this security to recover its value given our liquidity situation at that time.  The GPRE stock has recovered significantly.  Our recorded investment in GPRE at December 31, 2009, based upon the closing price of GPRE stock on the last trading day of 2009, is now carried at $5.4 million.

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

Distribution and Logistics

Due to severely declining margins and general liquidity stress due to frozen credit markets, we have significantly reduced the number of gallons we source from third parties.  As noted above, beginning in the fourth quarter of 2008 we began negotiating termination agreements with most of our marketing alliance partners and terminated all of them during 2009.  We recognized $10.2 million of income from the termination of our marketing alliance agreements during 2009.  Accordingly, we have also undertaken a strategy to rationalize our distribution and logistics system to focus primarily on our equity production.  At December 31, 2008, we had signed agreements for leased terminal capacity at 57 terminal locations.  During 2009, we subleased or assigned the majority of our railcar, barge and terminal leases.  We have aligned our distribution network in relation to production volumes from our equity-owned ethanol production facilities, and this distribution network has a cost structure that is comprised of minimal fixed cost commitments and is operated primarily on a variable cost basis.  At December 31, 2009, we had signed agreements for leased terminal capacity at only 3 terminal locations.

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

Legislative Drivers and Governmental Regulations

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

·                  The Energy Independence and Security Act of 2007;

·                  The federal ethanol tax incentive program;

·                  Federal tariff on imported ethanol;

·                  The use of fuel oxygenates; and

·                  Various state mandates.

The Energy Independence and Security Act of 2007

Enacted into law on December 19, 2007, the Energy Independence and Security Act of 2007 significantly increases the mandated usage of renewable fuels (ethanol, bio-diesel or any other liquid fuel produced from biomass or biogas).  The law increases the renewable fuels standard originally established under the Energy Policy Act of 2005 to 36 billion gallons by 2022, of which the mandate for corn-based ethanol is limited to 15 billion gallons annually from 2015 through 2022.

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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.  We cannot give assurance that the tax incentives will be renewed in 2010 or, if renewed, on what terms they will be renewed.  See “Item 1A — 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.

Ethanol imports from 24 countries in Central America and the Caribbean Islands are exempt from this tariff under the Caribbean Basin Initiative (“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 “Item 1A — 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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Customers

The substantial majority of our customer base has purchased ethanol from us for over five years (including our predecessor companies).  In 2009, 2008 and 2007, our 10 largest customers accounted for approximately 66%, 50% and 67%, respectively, of our consolidated ethanol sales volume.

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

Pricing and Backlog

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

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

Raw Materials and Suppliers

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

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

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.

Patents and Trademarks

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

Environmental and Regulatory Matters

We are subject to extensive federal, state and local environmental laws, regulations and permit conditions (and interpretations thereof), including those relating to the discharge of materials into the air,

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water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials, and the health and safety of our employees.  These laws, regulations, and permits require us to incur significant capital and other costs, including costs to obtain and maintain expensive pollution control equipment.  These regulations may also require us to make operational changes to limit actual or potential impacts to the environment.  A violation of these laws, regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns.  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, soil and groundwater contamination has been identified in the past at our Illinois campus.  If any of these sites are subject to investigation and/or remediation requirements, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws for all or part of the costs of such investigation and/or remediation, and for damages to natural resources.  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.  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, 2009.  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 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 caused by 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 for any expansion of existing facilities or any new 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 operating flexibility.  In addition, the permits ultimately issued may impose conditions which are more costly to implement than we had anticipated.  These costs could have a material adverse effect on our financial condition and results of operations.  Because other ethanol manufacturers in the U.S. are and will continue to be subject to similar laws and restrictions, we do not currently believe that our costs to comply with current or future environmental laws and regulations will adversely affect our competitive position among domestic producers.  However, because ethanol is produced and traded internationally, these costs could adversely affect us in our efforts to compete with foreign producers not subject to such stringent requirements.

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

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Illinois facilities.  The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility.  If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar investigation at our Nebraska facility due to the larger size of the Illinois wet mill facility.  In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.

We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the U.S. Environmental Protection Agency’s (“EPA”) National Emissions Standard for Hazardous Air Pollutants, or 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.  We expect the EPA will revise the rule to impose more stringent requirements than were contained in the vacated version.  In the absence of a final EPA 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.

We currently generate revenue from the sale of carbon dioxide, which is a co-product of the ethanol production process at each of our Illinois and Nebraska facilities.  New laws or regulations relating to the production, disposal or emissions of carbon dioxide may require us to incur significant additional costs and may also adversely affect our ability to continue generating revenue from carbon dioxide sales.

For more information about our environmental compliance and actual and potential environmental liabilities, see “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Uses of Liquidity — Capital Expenditures,” “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental Matters” and “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Subsequent Events.”

Employees

At December 31, 2009, we had a total of 302 full-time equivalent employees, compared to 346 as of December 31, 2008.  On March 13, 2009, we instituted a reduction in force of 26 employees, primarily as a result of the termination of our marketing alliance.  Approximately 55% of our current full-time employees (comprised of the hourly employees at our Illinois facilities) are represented by a union.  The unionized employees are covered by a collective bargaining agreement between our subsidiary, Aventine Renewable Energy, Inc. and the United Steelworkers International Union, Local 7-662 (the “Union”).  Our contract with the Union was scheduled to expire in October 2009.  Prior to the expiration of the collective bargaining agreement, the Company and the Union agreed to extend the term of the current collective bargaining agreement by one year through and including October 31, 2010 on the same terms and conditions, subject to an option to reopen negotiations upon mutual consent after the effective date of a confirmed Chapter 11 plan of reorganization.  There can be no assurances that we will be able to timely and successfully negotiate a new labor contract whose terms allow us to operate our business in today’s difficult operating environment.  If we are unable to timely and successfully negotiate a new labor contract, our business may be disrupted and our results of operations and financial condition may be negatively affected.

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Item 1A.  Risk Factors

The Company filed for reorganization under Chapter 11 on April 7, 2009 and is subject to the risks and uncertainties associated with the Bankruptcy Cases.

For the duration of the Bankruptcy Cases, our operations and our ability to execute our business strategy will be subject to the risks and uncertainties associated with bankruptcy. These risks include:

·                  our ability to continue as a going concern;

·                  our ability to operate within the restrictions and the liquidity limitations of our DIP Facility approved by the Bankruptcy Court in connection with the Bankruptcy Cases;

·                  our ability to obtain Bankruptcy Court approval with respect to motions filed in the Bankruptcy Cases from time to time;

·                  our ability to develop, confirm and consummate a plan of reorganization with respect to the Chapter 11 proceedings;

·                  the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization or to convert the Bankruptcy Cases to Chapter 7 cases;

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

·                  our ability to obtain and maintain normal payment and other terms with customers, vendors and service providers;

·                  our ability to attract, motivate and retain key employees;

·                  our ability to attract and retain customers; and

·                  our ability to fund and execute our Plan of Reorganization.

We may not be able to obtain confirmation of our Chapter 11  plan of reorganization, and our emergence from Chapter 11 proceedings is not assured.

The Plan was filed with the Bankruptcy Court on January 13, 2010.  In order to successfully emerge from Chapter 11 bankruptcy protection, we must obtain requisite court and creditor approval of, the Plan.  This process required us to meet statutory requirements with respect to adequacy of the Disclosure Statement, which was approved by the Bankruptcy Court on January 13, 2010, soliciting and obtaining creditor acceptance of a plan, and fulfilling other statutory conditions for plan confirmation.  We may not receive the requisite acceptances to confirm a plan.  Even if the requisite acceptances of a plan are received, the Bankruptcy Court may not confirm it.  For more information regarding the impact of the Plan on existing equity and issuance of new equity see “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations — Proposed Plan of Reorganization.”

If a plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if any, distributions holders of claims against us would ultimately receive with respect to their claims.

If a reorganization cannot be agreed upon, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity.  While we expect to emerge from Chapter 11 proceedings in the future, there can be no assurance as to whether we will successfully reorganize and emerge from Chapter 11 proceedings or, if we do successfully reorganize, as to when we would emerge from Chapter 11 proceedings.

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We will also be subject to risks and uncertainties with respect to the actions and decisions of our creditors and other third parties who have interests in the Bankruptcy Cases that may be inconsistent with our plans.

These risks and uncertainties could affect our business and operations in various ways.  For example, negative events or publicity associated with the Bankruptcy Cases could adversely affect our relationships with our vendors and employees, as well as with customers, which in turn could adversely affect our operations and financial condition.  Also, pursuant to the Bankruptcy Code, we need Bankruptcy Court approval for transactions outside the ordinary course of business, which may limit our ability to respond timely to events or take advantage of opportunities.  Because of the risks and uncertainties associated with the Bankruptcy Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 reorganization process may have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

As a result of the Bankruptcy Cases, realization of assets and liquidation of liabilities are subject to uncertainty.

While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements.  Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

A long period of operating under Chapter 11 could harm our business.

A long period of operating under Chapter 11 could adversely affect our business and operations.  So long as the Bankruptcy Cases continue, our senior management will be required to spend a significant amount of time and effort dealing with the Bankruptcy Cases instead of focusing exclusively on business operations.  A prolonged period of operating under Chapter 11 may also make it more difficult to attract and retain management and other key personnel necessary to the success and growth of our business.  In addition, the longer the Bankruptcy Cases continue, the more likely it is that our vendors will lose confidence in our ability to successfully reorganize our business, and they may seek to establish alternative arrangements for providing us with goods and services, including alternative payment arrangements, which in turn could have an adverse effect on our liquidity and/or results of operations.

Our having sought bankruptcy protection may also adversely affect our ability to negotiate favorable terms from suppliers, landlords, contract or trading counterparties and others and to attract and retain customers and counterparties.  The failure to obtain such favorable terms and to attract and retain customers and other contract or trading counterparties could adversely affect our financial performance.

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 DIP Facility.  Our liquidity position is significantly influenced by our operating results, which in turn are substantially dependent on commodity prices, especially prices for corn,

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ethanol, natural gas and unleaded gasoline.  As a result, adverse commodity price movements adversely impact our liquidity.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have limited access to additional financing.  In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with the Bankruptcy Cases and expect that we will continue to incur significant professional fees and costs.  We cannot assure you that the amounts of cash available from operations, together with our DIP Facility, will be sufficient to fund our operations, including operations during the period until such time as a plan of reorganization receives the requisite acceptance by creditors and is confirmed by the Bankruptcy Court.

Our liquidity and our ability to continue as a going concern, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of our DIP Facility; (ii) our ability to maintain adequate cash on hand; (iii) our ability to generate cash from operations; (iv) our ability to obtain confirmation of and to consummate a plan of reorganization under the Bankruptcy Code; (v) the cost and outcome of the reorganization process; and (vi) our ability to achieve profitability.  Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control.  Accordingly, there can be no assurance as to the success of our efforts.  In the event that cash flows and borrowings under our DIP 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.  Our access to additional financing is, and for the foreseeable future will likely continue to be, very limited.  Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time and ultimately cannot be determined until a plan of reorganization has been confirmed by the Bankruptcy Court.

The proposed Plan of Reorganization contemplates that, on the Effective Date, we will complete a $105 million offering of 13% senior secured notes due 2015 (the “Senior Secured Notes Offering”) the proceeds of which will, in part, be used to repay the DIP Facility in full.  In addition, the proposed Plan of Reorganization provides that, on or as soon as practicable after the Effective Date, we will close on a new credit facility with availability of up to $20 million (the “ABL Credit Facility”).  We cannot assure you that we will be able to obtain confirmation of the proposed Plan of Reorganization or effect the transactions contemplated thereby.  Even if we are able to obtain confirmation of the proposed Plan of Reorganization and effect the transactions contemplated thereby, we cannot assure you that the amounts of cash available from operations, together with the proceeds of the Senior Secured Notes Offering and/or the ABL Credit Facility will be sufficient to fund our operations.

We may be unable to secure additional financing.

Our ability to arrange, in addition to our DIP 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 for the last several months and may, as a result of the Bankruptcy Filing, 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;

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·                  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.

Although certain lenders have agreed to backstop/assure complete subscription to the Senior Secured Notes Offering in accordance with the terms of the backstop commitment agreement filed with the Plan (the “Backstop Commitment Agreement”), there can be no assurance that we will be able to satisfy the conditions set forth in the Backstop Commitment Agreement and effect the transactions contemplated thereby.

We may not have sufficient cash to service our indebtedness and other liquidity requirements.

Our ability to service our DIP Facility indebtedness and successfully consummate a plan of reorganization will depend, in part, on our ability to generate cash.  We cannot be certain that cash on hand together with cash from operations will by itself be sufficient to meet our cash and liquidity needs.  If we are unable to generate enough cash to meet our liquidity needs, we could be forced to discontinue some or all of our operations.

Our DIP Facility imposes operating and financial restrictions on us, compliance or non-compliance with which could have a material adverse effect on our liquidity and operations.

Restrictions imposed by the terms of our DIP Facility could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs and could result in an event of default under the DIP Facility.  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 on other than arm’s-length terms;

·                  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.

These limitations could have a material adverse effect on our liquidity and operations.  If we fail to comply with the restrictions under our DIP Facility and are unable to obtain a waiver or amendment or a default exists and is continuing under the DIP Facility, the lenders could declare outstanding borrowings and other obligations under the DIP Facility immediately due and payable.  Our ability to comply with these restrictions may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to

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reduce expenditures.  We cannot assure you that such waivers, amendments or alternative financing could be obtained, or if obtained, would be on terms acceptable to us.  If we are unable to comply with the terms of the DIP Facility, or if we fail to generate sufficient cash flow from operations, or, if it became necessary, to obtain such waivers, amendments or alternative financing, it could adversely impact the timing of, and our ultimate ability to successfully implement, a plan of reorganization.

The prices of our debt and equity securities are volatile, and, in connection with our reorganization, holders of our securities may receive no payment or payment that is less than the face value or purchase price of such securities.

Prior to the Bankruptcy Filing, the market price for our common stock was volatile and, following our Bankruptcy Filing, the price of our common stock has generally been less than $0.50 per share.  In addition, our common stock was delisted from the New York Stock Exchange prior to the Bankruptcy Filing and currently trades on the over-the-counter market.  Accordingly, trading in our common stock may be limited, and holders of such securities may not be able to resell their securities for their purchase price or at all.  We can make no assurance that the price of our common stock will not fluctuate substantially in the future.

It is possible that, in connection with our reorganization, all of the outstanding shares of common stock could be cancelled, and holders of our common stock may not be entitled to any payment in respect of their shares.  In addition, new shares of our common stock may be issued.  It is also possible that our obligations to holders of debt may be satisfied by payments to such holders that are less than both the par value of such securities and the price at which holders purchased such securities, or that shares of our common stock may be issued to certain of such holders in satisfaction of their claims.  The value of any common stock so issued may be less than the par value or purchase price of such holders’ securities, and the price of any such common shares may be volatile.

Accordingly, trading in our securities during the pendency of the Bankruptcy Cases is highly speculative and poses substantial risks to purchasers of such securities, as holders may not be able to resell such securities or, in connection with our reorganization, may receive no payment, or a payment or other consideration that is less than the par value or the purchase price of such securities.

For information regarding the treatment of holders of our securities under the proposed Plan of Reorganization see “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Proposed Plan of Reorganization.”

We may be subject to claims that will not be discharged in the Bankruptcy Cases, which could have a material adverse effect on our results of operations and profitability.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation and specified debts arising afterwards.  With few exceptions, all claims that arose prior to the Petition Date and before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization.  Any claims not ultimately discharged by the Bankruptcy Court could have an adverse effect on our results of operations and profitability.

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Bankruptcy laws may limit our secured creditors’ ability to realize value from their collateral.

Upon the commencement of a case for relief under Chapter 11, a secured creditor is prohibited from repossessing its security from a debtor in a Chapter 11 case, or from disposing of security repossessed from such debtor, without bankruptcy court approval.  Moreover, the Bankruptcy Code generally permits the debtor to continue to retain and use collateral even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.”  The meaning of the term “adequate protection” may vary according to circumstance, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security if and at such times as the Bankruptcy Court in its discretion determines that the value of the secured creditor’s interest in the collateral is declining during the pendency of the Chapter 11 proceedings.  The Bankruptcy Court may determine that a secured creditor may not require compensation for a diminution in the value of its collateral if the value of the collateral exceeds the debt it secures.

In view of the lack of a precise definition of the term “adequate protection” and the broad discretionary power of the Bankruptcy Court, we cannot reliably predict:

·                  how long payments under our secured debt could be delayed as a result of the Chapter 11 proceedings;

·                  whether or when secured creditors (or their applicable agents) could repossess or dispose of collateral;

·                  the value of the collateral; or

·                  whether or to what extent secured creditors would be compensated for any delay in payment or loss of value of the collateral through the requirement of “adequate protection.”

Furthermore, if the Bankruptcy Court determines that the value of the collateral is not sufficient to repay all amounts due on applicable secured indebtedness, the holders of such indebtedness would hold a secured claim only to the extent of the value of their collateral and would otherwise hold unsecured claims with respect to any shortfall.  The Bankruptcy Code generally permits the payment and accrual of post-petition interest, costs and attorneys’ fees to a secured creditor during a debtor’s Chapter 11 proceedings only to the extent the value of its collateral is determined by the Bankruptcy Court to exceed the aggregate outstanding principal amount of the obligations secured by the collateral.

Our financial results may be volatile and may not reflect historical trends.

While in bankruptcy, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements.  As a result, our historical financial performance is likely not indicative of our financial performance after the date of the Bankruptcy Filing.  In addition, if we emerge from bankruptcy, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization.  In addition, if we emerge from bankruptcy, we may be required to adopt fresh start accounting.  If fresh start accounting is applicable, our assets and liabilities will be recorded at fair value as of the fresh start reporting date.  The fair value of our assets and liabilities may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets.  In addition, if fresh start accounting is required, our financial results after the application of fresh start accounting may be different from historical trends.

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Conducting a successful Chapter 11 reorganization will depend significantly on our ability to retain and motivate management and key employees.

Our success depends significantly on the skills, experience and efforts of our personnel.  We do not maintain “key person” life insurance for any of our officers.  The loss of any of our officers could have a material adverse effect upon our results of operations and our financial position and could delay or prevent the achievement of our business objectives.  Our ability to develop and successfully consummate a plan of reorganization will be highly dependent upon the skills, experience and effort of our senior leadership and other personnel.  Our ability to attract, motivate and retain key employees is restricted, however, by provisions of the Bankruptcy Code, which limit or prevent our ability to implement a retention program or take other measures intended to motivate key employees to remain with the Company during the pendency of the Chapter 11 proceedings.  In addition, we may be required to obtain Bankruptcy Court approval of employment contracts and other employee compensation programs.  The loss of the services of one or more members of our senior leadership or certain employees with critical skills, or a diminution in our ability to attract talented, committed individuals to fill vacant positions when needs arise, could have a material adverse effect on our ability to successfully reorganize and emerge from bankruptcy.

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

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

The KEIP is limited to eight employees.  Pursuant to the KEIP, each of the eligible employees may be entitled to an incentive bonus payment if the Debtors meet or exceed certain specified targets, comprised of cash position, production level, and emergence date.  However, we can provide no assurance that the amounts of the bonuses provided in the KEIP will be adequate to assure the retention of key employees.

Transfers of our equity, or issuances of equity in connection with our restructuring or otherwise, may impair our ability to utilize our federal income tax net operating loss carryforwards in the future.

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) following the ownership change. 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.  While we do not believe that we have to date experienced an ownership change under Section 382, we believe we will experience an ownership change in the future as a result of changes in the ownership of our stock or future issuances of our stock, coincident with the confirmation of the Plan of Reorganization in our current Chapter 11 bankruptcy proceedings.

We have net operating loss carryforwards of approximately $1.5 million as of December 31, 2009.  If we undergo an ownership change for purposes of Section 382, our ability to recognize our built-in losses

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(including in the form of depreciation deductions on our assets) during the five-year period after the date of any ownership change would be subject to the limitations of Section 382.  Depending on the resulting limitation, our ability to use a significant portion of our future depreciation deductions could be limited, which could have the effect of creating or increasing our tax liabilities in years after such an ownership change, and have a negative impact on our financial position and results of operations.  During the pendency of the bankruptcy proceedings, the Bankruptcy Court has entered an interim order that places limitations on trading in our common stock, including options to acquire common stock, as further specified in the order.  However, we can provide no assurances that these limitations will prevent an “ownership change” or that our ability to utilize our net operating loss carryforwards may not be significantly limited as a result of our reorganization.

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

We are contractually obligated to develop both a 110 million gallon plant adjacent to our Nebraska facility and a two-phase 220 million gallon facility in Mount Vernon, Indiana and may incur significant penalties because of our failure to complete one or more of these facilities as previously scheduled, absent amendment of those obligations.

We may be subject to material penalties if we do not timely complete the Aurora West facility or the initial “Phase I” plant of the Mt. Vernon expansion.  The failure to complete the Aurora West plant by July 1, 2009 subjected the Company to contractual liquidated damages of $138,889 per month (up to a maximum of $5 million) until the plant is operational.  We suspended construction at Aurora West and did not complete it by July 1, 2009.  Accordingly, we may be required to pay some portion of the stipulated liquidated damages.  If we are unable to or otherwise do not pay these damages, the counterparty may have the right to repurchase the property at cost (subject to adjustment for any expenses which we have paid with respect to the infrastructure construction).  We recently amended our lease with the Indiana Ports Commission to provide additional flexibility as to the timing of Phase I and the Phase II expansion at Mt. Vernon.  This lease, as amended, requires our Mt. Vernon subsidiary to substantially complete Phase I (an initial 110 million gallons of capacity) by December 31, 2010 and to construct Phase II (an additional 110 million gallons of capacity) before constructing a new facility elsewhere.  If we are in default of these obligations, the Ports may, subject to specified cure rights, take over construction and complete the facility at our expense (among other remedies).  We suspended construction of Phase I at Mt. Vernon and have not commenced construction of Phase II.  The Plan contemplates the construction of Phase I at Mt. Vernon in 2010 and the assumption of the lease with the Ports, as amended, as well as assumption of the Master Development Agreement for the Aurora West facility, as amended, and the cure of amounts owing under that arrangement.

On March 9, 2009, we received a notice from our Engineering, Procurement and Construction (“EPC”) contractor, Kiewit Energy, cancelling the EPC contracts for Aurora West and Mt. Vernon, referencing our failure to make a required  payment.  Accordingly, we no longer have EPC contracts for the completion of Aurora West or Mt. Vernon.  Nevertheless, we are in the process of negotiating a new EPC contract with Kiewit to resume construction and, as referenced above, have made plans for the completion of one or more of the above plants.  However, there can be no certainty that such construction will be completed when or as planned, or at all.

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Restrictive covenants in the indenture governing the secured notes and the exit credit facility contemplated by the proposed Plan of Reorganization may adversely affect our business activities and operations.

The indenture governing the secured notes and the exit credit facility contemplated by the proposed Plan of Reorganization will contain various covenants that may adversely affect our ability to, among other things, incur additional indebtedness, incur liens, pay dividends or make certain restricted payments, consummate certain asset sales, merge, consolidate and/or sell or dispose of all or substantially all of our assets. In addition, the indenture governing the secured notes and the exit credit facility may require us and certain of our subsidiaries to maintain certain financial ratios and meet certain tests, including leverage and interest coverage ratios. Such covenants will also require us to use a portion of our cash flow and the proceeds we receive from certain asset sales and specified debt or equity issuances and upon the occurrence of other events to repay outstanding principal of the notes or borrowings under the exit credit facility.  These covenants may have important consequences on our operations, including, without limitation, restricting their ability to obtain additional financing and potentially limiting their ability to adjust to rapidly changing market conditions.

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

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

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

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

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

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

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

The principal raw material we use to produce ethanol and ethanol by-products is corn.  In 2009, we purchased approximately 74.2 million bushels of corn at a cost of $287.1 million, which comprised about 72% of our total cost of production.  In 2009, our average corn cost ranged from a low of $3.31 per bushel in September 2009 to a high of $4.48 per bushel in January 2009.  Corn prices began to rise significantly beginning in September 2006.  We believe a systemic shift has occurred in the marketplace for corn, and the price of corn will remain significantly higher than the historical averages.  The increase in U.S. ethanol capacity under construction could outpace increases in corn production, which may further increase corn prices and impact our profitability.

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

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

In an attempt to partially offset the effects of fluctuations in corn costs on operating income, we have taken hedging positions in the corn futures markets in the past.  However, these hedging transactions also involve risk to our business.  See “Item 1A —Risk Factors — We may engage in hedging or derivative transactions which involve risks that can harm our business.”

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

Substantial development of infrastructure by persons and entities outside our control are required for our operations and the ethanol industry generally, to grow.  Areas requiring expansion include, but are not limited to, additional rail capacity, additional storage facilities for ethanol, increases in truck fleets capable of transporting ethanol within localized markets, expansion of refining and blending facilities to handle ethanol, growth in service stations equipped to handle ethanol fuels, and growth in the fleet of flexible fuel vehicles capable of using E85 fuel.  Substantial investments required for these infrastructure

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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.

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.

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 renewable fuels standard, which requires an increasing amount of renewable fuels to be used in the U.S. each year, (2) the VEETC, which provided a tax credit of $0.51 per gallon (prior to January 1, 2009 when it was reduced to $0.45 per gallon) on 10% ethanol blends that is set to expire in 2010, (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 constantly changing.  Federal and state legislators and environmental regulators could adopt or modify laws, regulations or programs that could adversely affect 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.

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

The Energy Independence and Security Act of 2007 established a revised renewable fuels standard, or RFS, for the years 2006 through 2022.  The RFS sets forth the minimum amount of renewable fuels that must be present in U.S. transportation fuels.  The law starts at 9 billion gallons in 2008 and rises to 36 billion gallons by 2022.  For 2015 and all subsequent years, the amount of the renewable fuels mandate that can be satisfied by corn-based ethanol is currently capped at 15 billion gallons.  The remainder of the mandate is required to be obtained from cellulosic ethanol and other advanced biofuels.  If our and our competitors’ facilities cannot accept feedstocks, other than corn, or if we do not begin producing non-corn based ethanol in the future, our business, results of operations and financial condition may be adversely affected.

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

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

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 facilities are better suited to bringing in product by water rather than rail (the preferred path for ethanol from the Midwest).  The combination made it more economic for some buyers to import ethanol with the full import duty than to bring supplies from the Midwest.  Given the increase in ethanol demand as a result of the new RFS and potential transportation bottlenecks delivering material from the Midwest, imports of ethanol could rise.

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

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

We are subject to extensive federal, state and local environmental laws, regulations and permit conditions (and interpretations thereof), including those relating to the discharge of materials into the air, water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials, and the health and safety of our employees.  These laws, regulations, and permits require us to incur

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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 fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns.  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, soil and groundwater contamination has been identified in the past at our Illinois campus.  If any of these sites are subject to investigation and/or remediation requirements, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws for all or part of the costs of such investigation and/or remediation, and for damages to natural resources.  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.  We have not accrued any amounts for environmental matters as of December 31, 2009.  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 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 caused by 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 for any expansion of existing facilities or any new 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 operating flexibility.  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.

Federal and state environmental authorities have been investigating alleged excess VOCS emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities.  The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility.  If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar matter at our Nebraska facility due to the larger size of the Illinois wet mill facility.  In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.

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We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the EPA National Emissions Standard for Hazardous Air Pollutants, or NESHAP, for industrial, commercial and institutional boilers and process heaters.  This NESHAP 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.  We expect the EPA will revise the rule to impose more stringent requirements than were contained in the vacated version.  In the absence of a final EPA 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, which is a co-product of the ethanol production process at each of our Illinois and Nebraska facilities.  New laws or regulations relating to the production, disposal or emissions of carbon dioxide may require us to incur significant additional costs and may also adversely affect our ability to continue generating revenue from carbon dioxide sales.

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

The substantial majority of our net income is derived from the sale of ethanol and the related bio-products and co-products that we produce at our Illinois facilities and our Nebraska facility.  Our operations may be subject to significant interruption if either of the Illinois facilities or Nebraska facility experiences a major accident or is damaged by severe weather or other natural disaster.  In addition, our operations may be subject to labor disruptions and unscheduled downtime, or other hazards inherent in our industry.  Some of those hazards may cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, 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.

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

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manufacture of our products.  Our usage of natural gas will increase with the planned expansion of our production facilities.

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

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

Our distribution system allows us to carry an inventory of ethanol to better serve our customers and to take advantage of opportunities in the marketplace.  Our inventory is valued based upon a weighted average price we pay for ethanol that we purchase from our purchase/resale transactions, along with our own cost to produce ethanol.  In the past, we occasionally increased our inventory, in order to profit when we believed market prices would rise.  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 or its value is deemed to be impaired and can significantly increase or decrease our profitability.

We will recognize income from cancellation of indebtedness if our proposed Plan of Reorganization is approved.

If the Plan is confirmed, we will recognize income from cancellation of indebtedness (“COD”) when we emerge from bankruptcy to the extent that debt is discharged for consideration to a creditor for an amount that is less than the amount of such debt.  For these purposes consideration includes the amount of cash and the fair market value of property, including stock of the debtor, transferred to the creditor.  The amount of COD income, in general, is the excess of (a) the adjusted issue price of the indebtedness satisfied, over (b) the sum of the amount of cash paid and the fair market value of any new consideration (including the new stock of the Company following emergence from bankruptcy) given in satisfaction of the cancelled debt.  Although the precise amount of COD income that we will realize cannot be determined until the effective date of the Plan, we currently estimate that the amount of COD income we could realize will be approximately $135 million to $175 million for U.S. federal income tax purposes.

To the extent of COD income, we will be required to reduce certain of our tax attributes (principally, 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 (“ARRA”) 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.  We do not currently anticipate that we will make the deferral election for COD income, as described above.

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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 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, 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.

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

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

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

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

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

We sell ethanol to most of the major integrated oil companies and a significant number of large, independent refiners and petroleum wholesalers.  Our trade receivables result primarily from our ethanol marketing operations.  As a general policy, collateral is not required for receivables, but customers’ financial condition and creditworthiness are evaluated regularly.  Credit risk concentration related to our accounts receivable results from our top 10 customers having generated 54.7% and 47% of our consolidated net sales for the years ended December 31, 2009 and 2008, respectively.

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

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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.

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

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

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

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

The collective bargaining agreement with the Union was scheduled to expire in October 2009.  Prior to the expiration of the collective bargaining agreement, the Company and the Union agreed to extend the term of the current collective bargaining agreement by one year through and including October 31, 2010 on the same terms and conditions, subject to an option to reopen negotiations upon mutual consent after the effective date of a confirmed Chapter 11 plan of reorganization.  There can be no assurances that we will be able to timely and successfully negotiate a new labor contract with terms that allow us to operate our business in today’s difficult operating environment.  If we are unable to timely and successfully negotiate a new labor contract, our business may be disrupted and our results of operations and financial condition may be negatively affected.

We have a significant stockholder whose interests may differ from your interests and who may be able to exert significant influence over corporate decisions of the Company.

Through their ownership of Aventine Renewable Energy Holdings LLC, the MSCP funds beneficially own approximately 27.5% of our outstanding common stock.  Metalmark Subadvisor LLC, an affiliate of Metalmark, an independent private equity firm established by former principals of Morgan Stanley Capital Partners, manages certain MSCP funds on a sub-advisory basis.  In January 2008 substantially all of the employees of Metalmark became employees of Citi Alternative Investments Inc., although Metalmark remains an independent entity owned by those individuals and continues to manage

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the applicable MSCP funds on a sub-advisory basis. Two of our directors, Messrs. Abramson and Hoffman, are currently employees of both Metalmark and Citigroup.

As a result, Metalmark may be deemed to control our management and policies. Metalmark may have an interest in pursuing transactions that, in their judgment, enhance the value of the applicable funds’ equity investment in our Company, even though those transactions may involve risks to you as a stockholder.  In addition, circumstances could arise under which the interests of Metalmark could be in conflict with the interests of our other stockholders.  If we are able to obtain confirmation of the proposed Plan of Reorganization and effect the transactions contemplated thereby, we may have a new significant stockholder or group of significant stockholders.

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

We sell co-products and bio-products that are remnants of the ethanol production process in order to reduce our 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.

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

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

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

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 maintain all necessary permits from, governmental agencies;

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·                  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.

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.

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

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

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

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

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.

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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.

Item 1B.  Unresolved Staff Comments

There are no unresolved comments.

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Item 2.  Properties

Our corporate headquarters are located in Pekin, Illinois.  Listed below are our production facilities and land acquired for planned expansions/future developments:

Current Production Facilities:

Facilities Where Construction Has Begun But Is Currently Suspended:

Land for Future Expansion:

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

We believe that our existing facilities are adequate for our current and reasonably anticipated future needs, except in respect to our planned increases in production.

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Item 3.  Legal Proceedings

On April 7, 2009, the Company and all of its direct and indirect subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code with the United States Bankruptcy Court for the District of Delaware.  The Company’s subsidiaries that are part of the Bankruptcy Filing include Aventine Renewable Energy, LLC, a Delaware limited liability company; Aventine Renewable Energy, Inc., a Delaware corporation; Aventine Renewable Energy — Mt. Vernon, LLC, a Delaware limited liability company; Aventine Renewable Energy — Aurora West, LLC, a Delaware limited liability company; and Nebraska Energy, LLC, a Kansas limited liability company.  The Bankruptcy Cases are being jointly administered by the Bankruptcy Court under Case Number 09-11214 (KG).  We have operated and intend to continue operating our business as debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.  As a result of the filing, attempts to collect, secure, or enforce remedies with respect to pre-petition claims against Aventine are subject to the automatic stay provisions of Section 362 of the Bankruptcy Code.  The Bankruptcy Cases are discussed in greater detail in Note 2 to the accompanying condensed consolidated financial statements.

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 “Item 7 — 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.  Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the fourth quarter of 2009.

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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 is currently traded on the over-the-counter market (“OTC”) under the symbol “AVRNQ.”  We were previously traded on the New York Stock Exchange through March 29, 2009 under the symbol “AVR.”  Our common stock was delisted from the NYSE in March 2009 as a result of Aventine’s market capitalization falling below the NYSE’s $15 million required level for 30 consecutive days.  As of February 16, 2010, there were 43,443,078 shares of common stock outstanding held by 19 holders of record, based on the records of our transfer agent.

The following table sets forth, for the periods indicated, the range of high and low reported sale prices for our common stock on the New York Stock Exchange or OTC Bulletin Board, as applicable.

Dividends

We did not declare or pay cash dividends on our common stock during the years ended December 31, 2009 or 2008.  While in bankruptcy, we are effectively restricted from making dividend payments.

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Item 6.  Selected Financial Data

The historical consolidated financial data presented below should be read in conjunction with the information set forth under “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our Consolidated Financial Statements beginning on page F-1.

The balance sheet data presented below as of December 31, 2009 and 2008 and the statement of operations data presented below for each of the years in the three-year period ended December 31, 2009, are derived from our audited Consolidated Financial Statements beginning on page F-1.  The other balance sheet data and statement of operations data is derived from our previously audited consolidated financial statements included in our prior Form 10-K filings.

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(1)          Total debt includes amounts outstanding under:  1) our revolving credit agreement;  2) our senior unsecured notes in 2007 and 2008;  3) our debtor-in-possession debt facility; and  4) our previously outstanding senior, secured floating rate notes.  The senior unsecured notes are reflected in pre-petition liabilities subject to compromise at December 31, 2009.

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

(1)          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 United States and should not be considered an alternative to net earnings or any other measure of performance under accounting principles generally accepted in the U.S. or to cash flows from operating, investing or financing activities as an indicator of cash flows or as a measure of liquidity.

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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).

(2)          In order to emphasize the effects of non-recurring loss items in our financial statements, we have occasionally reported a second computation referred to as Adjusted EBITDA which adjusts EBITDA for those non-recurring loss items.

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

This Management’s Discussion and Analysis and certain other sections of this Form 10-K contain 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. Forward-looking statements are made pursuant to the safe harbor provisions of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are based on our beliefs as well as assumptions made by and information currently available to us.

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: changes in or elimination of laws, tariffs, trade or other controls or enforcement practices, environmental laws and regulations applicable to our operations and the enforcement thereof; changes in weather and general economic conditions; overcapacity within the ethanol, biodiesel and petroleum refining industries; total United States consumption of gasoline; availability and costs of products and raw materials; labor relations; fluctuations in petroleum prices; the impact on margins from a change in the relationship between prices received from the sale of co-products and the price paid for corn; our ability to generate free cash flow to invest in its business and service any indebtedness; limitations and restrictions contained in the instruments and agreements governing our indebtedness; our ability to raise additional capital and secure additional financing, and our ability to service such debt, if obtained; our ability to retain key employees; liability resulting from actual or potential future litigation; competition; plant shutdowns or disruptions at our plant or plants whose products we market; availability of rail cars and barges; our ability to complete our ethanol plant expansion projects in a timely manner and at the expected cost; our ability to receive and/or renew permits to construct and/or commence operations of our proposed capacity additions in a timely manner, or at all; and fluctuations in earnings resulting from increases or decreases in the value of ethanol or biodiesel inventory.

The following discussion of our consolidated operating results and financial condition for the three years ended December 31, 2009 should be read in conjunction with the Consolidated Financial Statements, and related notes beginning on page F-1.

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Chapter 11 Bankruptcy Proceedings

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 (collectively, the “Bankruptcy Filing”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) with the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”).  The Chapter 11 cases are being jointly administered by the Bankruptcy Court as Case No. 09-11214 (KG) (collectively, the “Bankruptcy Cases”).  The Debtors specifically are (i) Aventine Renewable Energy Holdings, Inc.; (ii) Aventine Renewable Energy, LLC, a Delaware limited liability company; (iii) Aventine Renewable Energy, Inc., a Delaware corporation; (iv) Aventine Renewable Energy — Mt. Vernon, LLC, a Delaware limited liability company; (v) Aventine Renewable Energy — Aurora West, LLC, a Delaware limited liability company; (vi) Aventine Power, LLC, a Delaware limited liability company, and (vii) Nebraska Energy, LLC, a Kansas limited liability company.

Subject to certain specific exceptions under the Bankruptcy Code, the Bankruptcy Filing automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date.  Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the property of the Debtors, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

The Bankruptcy Filing constituted an event of default under both the Company’s secured revolving credit facility and its 10% senior unsecured notes due 2017 (“the Notes”) (see Note 7), and those debt obligations became automatically and immediately due and payable, subject to an automatic stay of any action to collect, assert, or recover a claim against the Company and the application of applicable bankruptcy law.  As a result, the accompanying Consolidated Balance Sheet as of December 31, 2009 includes reclassifications of $309.7 million to reflect as “pre-petition liabilities subject to compromise” amounts owed to holders of the Notes, including pre-petition accrued interest, net of the unamortized debt issuance costs on the Notes.  The Company classifies “pre-petition liabilities subject to compromise” as a long-term liability because management does not believe the Company will use existing current assets or create additional current liabilities to fund these obligations.  Amounts owed under the Company’s pre-petition secured revolving credit facility and certain other collateralized obligations have not been included in “pre-petition liabilities subject to compromise” as they are  adequately collateralized.

Chapter 11 Process

The Debtors are currently operating as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.  In general, as debtors-in-possession, the Debtors are authorized under the Bankruptcy Code to continue to operate as an ongoing business, but may not engage in transactions outside of the ordinary course of business without the approval of the Bankruptcy Court.

On April 7, 2009, certain of the Company’s bondholders entered into a term sheet (the “DIP Term Sheet”) for a $30 million Debtor-in-Possession Credit Facility with the Debtors.  The DIP Term Sheet provides, subject to certain conditions as described in the Debtor-in-Possession Credit Facility Term Sheet filed as Exhibit 10.1 to our Form 8-K filed on April 13, 2009 for a first priority debtor-in-possession financing comprised of a term loan facility made available to certain of Aventine’s subsidiaries in a maximum aggregate principal amount of up to $30 million (the “DIP Facility”).  On May 5, 2009, the Bankruptcy Court overruled objections from the Debtors’ pre-petition secured lenders and approved the DIP Facility on a final basis.  Proceeds of the DIP Facility are available to, among other things, (i) fund the

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working capital and general corporate needs of the Debtors and the costs of the Bankruptcy Cases in accordance with an approved budget, and (ii) provide adequate protection, in accordance with the terms of the DIP Facility, to the pre-petition agent and pre-petition lenders under the Company’s existing credit facilities.  The DIP Facility bears interest at 16.5% per annum.  The maturity date of the DIP Facility is April 6, 2010, or upon the occurrence of certain pre-defined events.  The DIP Facility is secured by a super-priority administrative claim on our assets.

At a hearing held on April 9, 2009, the Bankruptcy Court granted the Debtors’ “First Day Motions.”  The relief granted by the Bankruptcy Court through the First Day Motions was designed to stabilize the Company’s operations and business relationships with vendors, lenders, employees and others, minimize the effects of the commencement of the Bankruptcy Cases and preserve the value of the Debtors’ assets.  The First Day Motions allowed, among other things, the payment of vendors and other providers in the ordinary course for goods and services ordered pre-petition but received on or after the Petition Date and other business-related payments necessary to maintain the operation of our businesses.  The First Day Motions also included the payment of pre-petition employee wages, salaries and benefits.  The Debtors have retained, with Bankruptcy Court approval, legal and financial professionals to advise the Debtors on the bankruptcy proceedings and certain other “ordinary course” professionals.  From time to time, the Debtors may seek Bankruptcy Court approval for the retention of additional professionals.

On or about April 29, 2009, the Debtors caused notice of the commencement of the Bankruptcy Cases to be served on all known or potential creditors and other parties in interest.  Vendors are being paid for goods furnished and services provided after the Petition Date in the ordinary course of business.

As required by the Bankruptcy Code, the United States Trustee for Delaware appointed an official committee of unsecured creditors (the “Creditors’ Committee”). The Creditors’ Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court with respect to the Debtors.  There can be no assurance that the Creditors’ Committee will support the Debtors’ positions on matters to be presented to the Bankruptcy Court in the future or on any plan of reorganization.  Disagreements between the Debtors and the Creditors’ Committee could protract the Bankruptcy Cases, negatively impact the Debtors’ ability to operate, and delay the Debtors’ emergence from the Chapter 11 proceedings.

Under Section 365 of the Bankruptcy Code, the Debtors may assume, assume and assign, or reject executory contracts and unexpired leases, including real property, railcars and equipment leases, subject to the approval of the Bankruptcy Court and certain other conditions.  Rejection constitutes a court-authorized breach of the lease or contract in question and, subject to certain exceptions, relieves the Debtors of future obligations under such lease or contract, but creates a pre-petition claim for damages caused by such breach or rejection, subject to the Debtors’ right to review and contest such claim.  Parties whose contracts or leases are rejected may file claims against the Debtors for damages.  Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure all prior defaults under such executory contract or unexpired lease, including all pre-petition arrearages, and to provide adequate assurance of future performance.  In this regard, the Debtors’ financial statements include amounts classified as “pre-petition liabilities subject to compromise” that the Debtors believe that the Bankruptcy Court will allow as claim amounts as a result of the Debtors’ rejection of various executory contracts and unexpired leases.  Additional amounts may be included in “pre-petition liabilities subject to compromise” in future periods if additional executory contracts and unexpired leases are rejected.  Conversely, the Debtors would expect that the assumption of certain executory contracts and unexpired leases may convert certain liabilities shown in future financial statements as subject to compromise to post-petition liabilities.  Due to the uncertain nature of many of the potential claims, the Debtors are unable to project the magnitude of such claims with any degree of certainty.

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The Bankruptcy Court established September 8, 2009 at 4:00 p.m. eastern time as the deadline for the filing of proofs of claim, thereby requiring the Debtors’ creditors to submit claims for alleged liabilities not paid and/or damages incurred arising from or related to periods prior to the Petition Date.  In certain cases, differences exist between the amounts at which the Company has recorded liabilities for rejected contracts and other pre-petition liabilities in the Company’s financial statements and the amount claimed by Aventine’s creditors based on the Company’s estimate of the magnitude of claim to be allowed by the Bankruptcy Court.  Significant litigation may be required to resolve any such disputes or discrepancies.

In order to successfully exit Chapter 11, the Debtors will need to obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code.  A plan of reorganization could, among other things, resolve the Debtors’ pre-petition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to exit from bankruptcy.  As provided in the Bankruptcy Code, the Debtors have the exclusive right for 120 days after the Petition Date to file a plan of reorganization and 60 additional days to solicit and obtain necessary acceptances.  Such periods may be extended by the Bankruptcy Court for cause to up to 18 months and 20 months, respectively, after the Petition Date.  If the Debtors’ exclusivity period lapses, any party in interest may file a plan of reorganization for Aventine.  The Debtors have filed three motions with the Bankruptcy Court requesting extension of the exclusive filing and solicitation deadlines under Section 1121 of the Bankruptcy Code.  The first motion, approved by the Bankruptcy Court by order dated August 18, 2009, extended the exclusive deadline to file a plan of reorganization to October 5, 2009 and the solicitation of the necessary acceptances to December 3, 2009.  The second motion, approved by the Bankruptcy Court by order dated October 27, 2009 further extended the exclusive deadline to file a plan of reorganization through and including December 4, 2009 and the exclusive solicitation period through and including February 1, 2010.  The third motion, approved by the Bankruptcy Court by order dated January 7, 2010 further extended the exclusive deadline to file a plan of reorganization through and including March 4, 2010 and the exclusive solicitation period through and including May 3, 2010.

On December 4, 2009, the Debtors filed the Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009 (as amended, “the Plan”) and the Disclosure Statement for the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009 (as amended, “the Disclosure Statement”).

On January 13, 2010, the Bankruptcy Court approved an order allowing the Debtors’ entry into the Backstop Commitment Agreement related to the offering of new senior secured notes and equity through the Plan.  The Bankruptcy Court, also on January 13, 2010, approved the Disclosure Statement as containing adequate information as required by section 1125 of the Bankruptcy Code and thus entered the Order (I) Approving the Disclosure Statement; (II) Establishing Procedures for Solicitation and Tabulation of Votes to Accept or Reject the Plan, Including (A) Approving Form and Manner of Solicitation Procedures, (B) Approving the Form and Notice of the Confirmation Hearing, (C) Establishing Record Date and Approving Procedures for Distribution of Solicitation Packages, (D) Approving Forms of Ballots, (E) Establishing Deadline for Receipt of Ballots, and (F) Approving Procedures for Vote Tabulations; (III) Establishing Deadline and Procedures for Filing Objections to (A) Confirmation of the Plan, and (B) the Debtors’ Proposed Cure Amounts for Unexpired Leases and Executory Contracts Assumed Pursuant to the Plan; (IV) Approving the Secured Notes Offering Procedures; and (V) Granting Related Relief.  The Bankruptcy Court established January 13, 2010 as the record date for purposes of determining which creditors and interest holders are entitled to vote on the Plan and receive materials in connection with the solicitation of votes to accept or reject the Plan, including notices of non-voting status.  The voting deadline for the holders of claims and interest holders entitled to vote under the Plan was established by the Bankruptcy Court as February 17, 2010.

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Pursuant to section 1128 of the Bankruptcy Code, the Bankruptcy Court has scheduled a hearing to consider confirmation of the Plan for February 24, 2010 at 3:00 p.m. prevailing eastern time before the Honorable Kevin Gross, United States Bankruptcy Court, 824 North Market Street, 6th Floor, Wilmington, Delaware 19801 (the “Confirmation Hearing”).  The Bankruptcy Court has directed that objections, if any, to confirmation of the Plan be served and filed so that they are received on or before February 17, 2010 at 4:00 p.m., prevailing eastern time.  The Confirmation Hearing may be adjourned from time to time by the Bankruptcy Court without further notice except for the announcement of the adjournment date made at the Confirmation Hearing or at any subsequent adjourned Confirmation Hearing. Chapter 11 of the Bankruptcy Code provides that unless the terms of section 1129(b) of the Bankruptcy Code are satisfied, for a bankruptcy court to confirm a Chapter 11 plan as a consensual plan, the holders of impaired claims against a debtor in each class of impaired claims must accept such plan by the requisite majorities set forth in the Bankruptcy Code.  An impaired class of claims shall have accepted a Chapter 11 plan if (a) the holders of at least two-thirds in amount of the claims in such class actually voting on a plan have voted to accept it, and (b) more than one-half in number of the holders in such class actually voting on the plan have voted to accept it.  Pursuant to the provisions of the Bankruptcy Code, only holders of allowed claims or equity interests in classes of claims or equity interests that are impaired and that are not deemed to have rejected a Chapter 11 plan are entitled to vote to accept or reject such proposed plan.  Generally, a claim or interest is impaired under a plan if the holder’s legal, equitable or contractual rights are altered under such plan.  Classes of claims or equity interests under a Chapter 11 plan in which the holders of claims or equity interests are unimpaired are deemed to have accepted such plan and are not entitled to vote to accept or reject the proposed plan.  In addition, classes of claims or equity interests in which the holders of claims or equity interests will not receive or retain any property on account of their claims or equity interests are deemed to have rejected the plan and are not entitled to vote to accept or reject the plan.  Under circumstances specified in the so-called “cramdown” provisions of Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes.  The precise requirements and evidentiary showing for confirming a Chapter 11 plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests, in the rejecting class — i.e., secured claims or unsecured claims, subordinated or senior claims, or common stock.

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, post-petition liabilities and pre-petition liabilities must be satisfied in full before stockholders of the Debtors are entitled to receive any distribution or retain any property under a plan of reorganization.  The ultimate recovery, if any, to creditors and stockholders of the Debtors will not be determined until confirmation and consummation of a plan of reorganization.  No assurance can be given as to what values, if any, will be ascribed in the Bankruptcy Cases to each of these constituencies or what types or amounts of distributions, if any, they would receive.  Accordingly, the Debtors urge that appropriate caution be exercised with respect to existing and future investments in any of the Company’s common stock or any of the Company’s liabilities.

Although the Debtors filed the Plan, which provides for emergence from Chapter 11 some time in the future, there can be no assurance that the Plan, or any other Chapter 11 plan, will be confirmed by the Bankruptcy Court, or that any such chapter 11 plan will be consummated.  In order to successfully emerge from chapter 11, the Debtors will need to, among other things, obtain alternative financing to replace the DIP Facility.  The Company has filed the Disclosure Statement, which was approved by the Bankruptcy Court as containing adequate information under section 1125 of the Bankruptcy Code, and the Plan, that includes a backstop lending agreement, which may be confirmed at a hearing on February 24, 2010.  For further discussion, see “Item 7 — Management Discussion and Analysis of Financial Condition and Results of Operations.”

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The Debtors have incurred and will continue to incur significant costs associated with the reorganization.  The amount of these costs, which are being expensed as incurred, are expected to significantly affect the Debtors’ results of operations.

Notice and Sell-Down Procedures for Trading Equity Securities

The Bankruptcy Court entered a final order (the “Final Trading Restriction Order”) on May 4, 2009 granting a motion of the Debtors to require beneficial owners of substantial amounts of the Company’s common stock to provide notice of their holdings and restrict, in specified circumstances and subject to specified terms and conditions, acquisitions or dispositions of the Company’s common stock by Substantial Equityholders (as defined below) (the “Common Stock Notice and Transfer Requirements”).

Under the Common Stock Notice and Transfer Requirements, all “Substantial Equityholders” must provide the Debtors, the Debtors’ counsel and the Bankruptcy Court advance notice of their intent to buy or sell the Company’s common stock (including options to acquire common stock, as further specified in the Final Trading Restriction Order) prior to effectuating any such purchase or sale.  A “Substantial Equityholder” under the Final Trading Restriction Order is a person or entity that beneficially owns or, as a result of a transaction, would beneficially own, at least 2.04 million shares (including options to acquire shares, as further specified in the Final Trading Restriction Order) of the Company’s common stock, representing approximately 4.75% of all issued and outstanding shares of the Company’s common stock.  The Common Stock Notice and Transfer Requirements were requested by the Debtors to identify and, where necessary, restrict potential trades of the Company’s common stock that could negatively impact the Debtors’ ability to preserve maximum availability of their accrued net operating losses and other tax attributes under Section 382 of the Code.  Pursuant to the Final Trading Restriction Order, the Debtors have 15 calendar days after notification of a transfer by a Substantial Equityholder to file any objections with the Bankruptcy Court and serve notice on such Substantial Equityholder.  If the Debtors file any objections, the transfer would not become effective unless approved by a final and non-appealable order of the Bankruptcy Court.  In addition, a person or entity that is or becomes a Substantial Equityholder must file with the Bankruptcy Court, and provide the Debtors and their counsel with, notification of such status on or before the later of (a) 15 days after the effective date of the notice of entry of the Final Trading Restriction Order or (b) ten days after becoming a Substantial Equityholder.

Proposed Plan Of Reorganization

On December 4, 2009 the Debtors filed the Initial Chapter 11 Plan and accompanying Disclosure Statement.  The Company subsequently filed the Plan and Disclosure Statement on January 13, 2010.  A hearing has been scheduled by the Bankruptcy Court for February 24, 2010 to consider confirmation of the Plan.  Under that Plan, the Company has classified the Claims and Equity Interests (as defined in the Plan).  All Claims and Equity Interests, except Administrative Claims, DIP Financing Claims, Fee Claims, and Priority Tax Claims, are placed in Classes set forth below.  In accordance with section 1123(a)(1) of the Bankruptcy Code, Administrative Claims, DIP Financing Claims, Fee Claims and Priority Tax Claims have not been classified.

1.               Unclassified Claims (not entitled to vote on the Plan)

a.               Administrative Claims

b.              DIP Financing Claims

c.               Fee Claims

d.              Priority Tax Claims

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2.               Unimpaired Classes of Claims (deemed to have accepted the Plan and therefore not entitled to vote on the Plan)

a.               Classes 1(a) — (f): Other Priority Claims

b.              Classes 3(a) — (f): Other Secured Claims

c.               Class 4(a): Kiewit Mt. Vernon Secured Claim

d.              Classes 8(a) — (f):  Intercompany Claims.

3.               Impaired Classes of Claims

a.               Classes 2(a) — (f): Prepetition Secured Credit Facility Claims

b.              Class 4(b): Kiewit Aurora West Secured Claim

c.               Classes 5(a) — (f):  Prepetition Unsecured Notes Claim

d.              Classes 6(a) — (f):  General Unsecured Claims

e.               Classes 7(a) — (f):  Convenience Claims

f.                 Class 9(a):  Equity Interests

Holders of Equity Interests in Classes 9(b) — (f) are deemed to reject the Plan since they are not receiving distributions or retaining any property under the Plan and therefore are not entitled to vote on the Plan.

If the Plan is approved by the Bankruptcy Court, upon the occurrence of the Effective Date (as defined in the Plan), holders of Allowed Claims and Equity Interests in Class 9(a) will be entitled to receive the distribution provided in the Plan, which, depending on the nature of the Allowed Claim, could be either a specified cash payment, cash and debt, equity or warrants in the new company’s (“Reorganized Aventine”) common stock.  The existing outstanding common stock of Aventine Renewable Energy Holdings, Inc. will be terminated and 8,550,000 shares of new common stock will be issued.  Approximately 6,840,000 shares of new common stock, or 80% of the issued and outstanding shares on the Effective Date will be reserved as the Unsecured Claims Stock Pool to be allocated pro rata to the Allowed Prepetition Unsecured Notes Claims (Class 5) and the Allowed General Unsecured Notes Claims (Class 6), subject to dilution by warrants and stock awards issued under the Management Incentive Plan.  As described further below, 1,710,000 shares of new common stock (“Noteholder New Equity”) will be reserved for the pro rata allocation to purchasers of a $105 million offering of 13% Senior Secured Notes due in 2015 provided for in the Plan to provide funds to support he Company through emergence, subject to dilution by warrants and stock awards issued under the Management Incentive Plan.  Warrants for purchase of an aggregate 5.0% of the common stock on a fully-diluted basis priced ate $40.94 per share will be distributed pro rata to holders of the Company’s existing outstanding common stock.

Pursuant to the Plan, the failure of Reorganized Aventine to meet any of the obligations described above with respect to the Exchange Registration or Resale Registration shall result in additional interest becoming payable with respect to the Senior Secured Notes (including notes issued in the Exchange Registration) in the amount of 2.0%.

Under the Plan, holders of the Allowed Prepetition Unsecured Notes Claims (Class 5) shall be entitled to subscribe and acquire their pro rata share of (i) $105 million in aggregate principal amount of the Senior Secured Notes and (ii) the shares of Noteholder New Equity.  1,710,000 shares of new common stock will be distributed pro rata with subscriptions to the Senior Secured Notes.  The proceeds of the issuance of the Senior Secured Notes shall be used to (i) make payments required to be made on or after the Effective Date under the Plan, including, without limitation, repayment of all amounts owing under the DIP Facility and payments required to be made to holders of Prepetition Secured Credit Facility Claims (Class 2), and (ii) fund working capital and general corporate needs of Reorganized Aventine.

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Certain lenders (Backstop Purchasers) have agreed to backstop/assure complete subscription to the Senior Secured Notes Offering in accordance with the terms of the Backstop Commitment agreement filed with the Plan.  In addition, the Plan provides that on or as soon as practicable after the Effective Date, Reorganized Aventine shall close on the ABL Credit Facility.  The amounts borrowed under the ABL Credit Facility will be used to fund Reorganized Aventine’s working capital needs after the Effective Date.

Going Concern Matters

The ability of the Company to continue as a going concern is dependent upon, among other things, (i) the Company’s ability to comply with the terms and conditions of the DIP Facility; (ii) the ability of the Company to maintain adequate cash on hand; (iii) the ability of the Company to generate cash from operations; (iv) the ability of the Company to obtain confirmation of and to consummate a plan of reorganization under the Bankruptcy Code; (v) the cost and outcome of the reorganization process; (vi) the Company’s ability to obtain alternative financing; and (vii) the Company’s ability to achieve profitability.  Uncertainty as to the outcome of these factors raises substantial doubt about the Company’s ability to continue as a going concern.  The Company is currently evaluating various courses of action to address the issues the Company is facing.  There can be no assurance that any of these efforts will be successful.

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

We have prepared  the consolidated financial statements in accordance with ASC 852.  This guidance requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business.  Accordingly, certain expenses (including professional fees), realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in reorganization items on the accompanying Consolidated Statements of Operations.  In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the  Consolidated Balance Sheet at December 31, 2009 in “pre-petition liabilities subject to compromise.”  These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.  For information on the bankruptcy reorganization process, see Note 2 - Chapter 11 Bankruptcy Proceedings.

Company Overview

Aventine is a producer of ethanol.  Through our production facilities, we market and distribute ethanol to many of the leading energy companies in the U.S.  In addition to producing ethanol, our facilities also produce several co-products including: corn gluten feed and meal, corn germ, condensed corn distillers solubles, dried distillers grain with solubles (“DDGS”), wet distillers grain with solubles (“WDGS”), carbon dioxide and brewers’ yeast.

Executive Summary — Results of Operations

We generated a net loss of $46.3 million, or $1.08 per diluted share in 2009, as compared to a net loss of $47.1 million, or $1.12 per diluted share, in 2008.  The 2009 net loss was significantly increased by $32.4 million in reorganization items resulting from the Company’s Chapter 11 bankruptcy filing. Revenue in 2009 decreased to $594.6 million as compared to $2.2 billion in 2008.

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Gallons of ethanol sold in 2009 decreased to 277.5 million from 936.0 million in 2008.  With severely declining gross profit margins and general liquidity stress due to frozen credit markets, we negotiated termination agreements with our marketing alliance partners and began to rationalize our distribution network to primarily focus on sales of our equity production  beginning in the fourth quarter of 2008.  We completed the termination of our marketing alliance and scaled back our purchase/resale program during the first quarter of 2009.  The average gross selling price of ethanol in 2009 decreased to $1.75 per gallon, from the $2.22 received in 2008.  Ethanol production for 2009 totaled 197.5 million gallons, a slight increase from 188.8 million gallons in 2008.  Gross profit for 2009 decreased slightly to $8.7 million from $9.0 million in  2008.  Negative gross margin through the third quarter of 2009 was offset by a positive gross margin of $22.2 million in the fourth quarter.

In 2009, the Company recognized income from the termination of marketing agreements with alliance partners totaling $10.2 million.  The 2008 net loss was increased as a result of $33.2 million in nonrecurring losses comprised of $31.6 million related to the sale of its 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 the Pekin site.

General

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

Variability of Gross Profit

Our gross profit has fluctuated and may continue to fluctuate substantially from period to period.  Gross profit from ethanol sales is mainly affected by changes in selling prices for ethanol, the cost to us 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 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.  See “Item 1A — Risk Factors — Our business is dependent upon the availability and price of corn.  Significant disruptions in the supply of corn will materially affect our operating results.  In addition, since we generally cannot pass on increases in corn prices to our customers, continued periods of historically high corn prices will also materially adversely affect our operating results,” and “Item 1A — Risk Factors — The market for natural gas is subject to market conditions that create uncertainty in the price and availability of the natural gas that we utilize in our manufacturing process.”  Since both natural gas and ethanol are energy-related products, there has been significant, although not perfect, correlation between their market prices.  As a result, at times when natural gas prices had increased, thereby increasing our costs, ethanol prices have typically increased, thereby increasing our revenues and offsetting some of the impact on our results of operations.

Conversion Costs

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

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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”).

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

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

As a result of the Bankruptcy Filing, realization of assets and liquidation of liabilities are subject to uncertainty.  While operating as a debtor-in-possession under the protection of Chapter 11, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, the Debtors may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in the condensed consolidated financial statements.  Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated financial statements.  Our historical consolidated financial statements do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

Share-based Compensation Expense

Effective January 1, 2006, we adopted, on a modified prospective transition method, Accounting Standards Codification 718, Compensation — Stock Compensation (“ASC 718”), which requires measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including stock options, based on fair values.  Share-based compensation expense recognized is based on the value of the portion of share-based payment awards that is ultimately expected to vest.  Share-based compensation expense recognized in our Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007 include compensation expense for unvested share-based payment awards granted prior to December 31, 2005, based on the grant date fair value estimated in accordance with the minimum value method as outlined in ASC 718, and compensation expense for the share-based payment awards granted subsequent to December 31, 2005 based on the grant date fair value estimated in accordance with the provisions of ASC 718.  In conjunction with the adoption of ASC 718, we elected to attribute the value of share-based compensation to expense over the periods of requisite service using the straight-line method.

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

Inventory

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

Derivatives and Hedging Activities

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

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

ASC 815 requires a company to evaluate contracts to determine whether the contracts are derivatives.  Certain contracts that meet the literal definition of a derivative under ASC 815 may be exempted from the accounting and reporting requirements of ASC 815 as normal purchases or normal sales.  Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business.  The Company elects to designate its forward purchases of corn and forward sales of ethanol as normal purchases and sales under ASC 815.  Accordingly, these contracts are not recorded in our financial results until performance under them occurs.

Income Taxes

Under Accounting Standards Codification 740, Income Taxes (“ASC 740”), deferred tax liabilities and assets are recorded for the expected future tax consequences of events that have been recognized in our

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financial statements or tax returns.  Property, plant and equipment, stock-based compensation expense and investments in marketing alliance partners are the primary sources of these temporary differences.  Deferred income taxes also includes net operating loss and capital loss carryforwards.  The Company establishes valuation allowances to reduce deferred tax assets to amounts it believes are realizable and contingency reserves for implemented tax planning strategies.  These valuation allowances and contingency reserves are adjusted based upon changing facts and circumstances.

Pension and Postretirement Benefit Costs

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

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

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

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

Revenue Recognition

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

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

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

Results of Operations

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

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

For the Year Ended December 31,

*  Not meaningful

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

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

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

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

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at an average cost of $1.56 per gallon as compared to 754.3 million gallons of ethanol at an average cost of $2.04 in 2008.

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

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

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

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

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

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

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

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

Interest expense in 2009 was $14.7 million, as compared to $5.1 million in 2008.  Interest expense in 2009 consists of $8.1 million  on our $300 million aggregate principal amount of senior unsecured 10% fixed-rate notes, $2.5 million on borrowing on our secured revolving credit facility, $2.3 million for amortization of deferred financing fees, and $1.8 million on our debtor-in-possession debt facility.  We ceased  the accrual of interest on the senior unsecured notes as of the bankruptcy petition date.  Interest expense capitalization was suspended with the halting of the expansion projects at Mt. Vernon and Aurora West.  Interest expense in 2008 was reduced by the capitalization of $26.4 million in interest expense on the expansion projects.

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

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

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

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

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

For the Year Ended December 31,

* N.M. — not meaningful

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

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

Cost of goods sold for 2008 was $2.2 billion, a significant increase over the $1.5 billion in 2007.  Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from our marketing alliance partners, the cost of purchasing ethanol and bio-diesel from other

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producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers.

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

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

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

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

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

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

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

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

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

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Interest expense in 2008 was $5.1 million, as compared to $16.2 million in 2007.  Interest expense in 2008 reflected $30 million of interest incurred on our $300 million aggregate principal amount of senior unsecured 10% fixed-rate notes and $1.5 million of interest on our secured revolving credit facility, net of $26.4 million of capitalized interest.  In 2007, our senior unsecured 10% fixed-rate notes were only outstanding from March to December.

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

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

The Company’s annual tax rate for 2008 was 13.7% of pre-tax loss.  The income tax benefit recorded in 2008 was net of a valuation allowance of $16.1 million.  The valuation allowance recognized on our gross deferred tax assets reduced our deferred tax asset to the amount we believed was more likely than not to be realized.  The valuation allowance included $12.3 million of reserve against the income tax benefit related to the losses incurred on auction rate securities as we did not expect to have sufficient capital gains to offset the $31.6 million capital loss.

Trends and Factors that May Affect Future Operating Results

Bankruptcy

If the Plan is confirmed and is declared effective during the first quarter of 2010, the Company will continue to incur reorganization related professional fees and costs for some time, will experience a reduction in its tax attributes related to the COD income it will realize which will reduce future tax benefits, will have a new ownership structure, and will have significantly fewer liabilities.  Any one or more of these factors could impact the Company’s performance in the near future.  Operation of the Company’s ethanol facilities should not be affected by the emergence from bankruptcy.

Supply and Demand

Through November 2009, U.S. ethanol demand exceeded U.S. ethanol production by 139 million gallons.  Demand for ethanol increased by 12% over 2008 through increased penetration into new markets, and a government mandate but, the production capacity of U.S. ethanol producers continues to exceed demand.  At the end of 2009, there was approximately 1.2 billion gallons of production capacity shut-in.  If additional demand for ethanol is not created, either through discretionary blending or an increase in the blending percentage allowed by the EPA, the excess supply may cause additional plants to shutter production or cause ethanol prices to decrease further, perhaps substantially.

Commodity Prices

Our primary grain feedstock is corn.  The cost of corn is dependent upon factors that are generally unrelated to those affecting the selling price of ethanol.  Corn prices generally vary with international and

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regional grain supplies, and can be significantly affected by weather, planting and carryout projections, government programs, exports, and other international and regional market conditions.  Due to the significant expansion of the ethanol industry, corn futures have increased substantially as compared to historical averages.  This trend is likely to continue and will have a material impact on our results of operation and financial condition.  In addition, factors such as USDA estimates of acres planted, export demand and other domestic usage also have significant effects on the corn market.  Weather-related impacts upon the corn market and prices are expected to be mitigated by new more resilient hybrid varieties of corn.

We have purchased forward approximately 1.4 million bushels (or approximately 8%) of our corn requirements for the first quarter of 2010 at an average price of $3.95 per bushel.

Natural Gas Prices

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

Ethanol Supports

We receive significant benefits from federal and state statutes, regulations and programs and the trend at the governmental level appears to be to continue to try to provide economic support to the ethanol industry.  Notwithstanding the above, changes to federal and state statutes, regulations or programs could have an adverse effect on our business.  Recent federal legislation, however, has been of benefit to the ethanol industry.  In December 2007, the Energy Independence and Security Act of 2007 was passed which contained a new increased RFS.  The new RFS requires fuel refiners to use a certain minimum amount of renewable fuels (including ethanol) which will rise from 12.95 billion gallons in 2010 to 36 billion gallons by 2022.  Ethanol benefits from an excise tax credit of $0.45 per ethanol gallon (prior to January 1, 2009, the excise tax credit was $0.51 per gallon).  This excise tax credit provides incentives for blenders and refiners to blend ethanol with gasoline.

Expansion

We have suspended construction of our plants in Aurora and Mt. Vernon.  We remain contractually obligated to complete construction of the suspended plants at Aurora and Mt. Vernon and may incur significant penalties because of our failure to complete these facilities as previously scheduled.  See “Item 1 — Risk Factors — We are contractually obligated to complete certain capacity expansions in Aurora, Nebraska and Mount Vernon, Indiana.  If we fail to complete them in a timely manner we may be subject to material penalties.”

Cancellation of indebtedness income

We will recognize income from cancellation of indebtedness (“COD”) when we emerge from bankruptcy to the extent that debt is discharged for consideration to a creditor for an amount that is less than the amount of such debt.  For these purposes consideration includes the amount of cash and the fair market value of property, including stock of the debtor, transferred to the creditor.  The amount of COD income, in general, is the excess of (a) the adjusted issue price of the indebtedness satisfied, over (b) the sum of the amount of cash paid and the fair market value of any new consideration (including the new stock of the Company following emergence from bankruptcy) given in satisfaction of the cancelled debt.  Although the precise amount of COD income that we will realize cannot be determined until the effective date of the Plan

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of Reorganization, we currently estimate that the amount of COD income we could realize will be approximately $135 million to $175 million for U.S. federal income tax purposes.

To the extent of COD income, we will be required to reduce certain of our tax attributes (principally, 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 (“ARRA”) 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) following the ownership change. 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.  While we do not believe that we have to date experienced an ownership change under Section 382, we believe we will experience an ownership change in the future as a result of changes in the ownership of our stock or future issuances of our stock, coincident with the confirmation of the Plan of Reorganization in our current Chapter 11 bankruptcy proceedings.

We have net operating loss carryforwards of approximately $1.5 million as of December 31, 2009.  If we undergo an ownership change for purposes of Section 382, our ability to recognize our built-in losses (including in the form of depreciation deductions on our assets) during the five-year period after the date of any ownership change would be subject to the limitations of Section 382.  Depending on the resulting limitation, our ability to use a significant portion of our future depreciation deductions could be limited, which could have the effect of creating or increasing our tax liabilities in years after such an ownership change, and have a negative impact on our financial position and results of operations.  During the pendency of the bankruptcy proceedings, the Bankruptcy Court has entered an interim order that places limitations on trading in our common stock, including options to acquire common stock, as further specified in the order.  However, we can provide no assurances that these limitations will prevent an “ownership change” or that our ability to utilize our net operating loss carryforwards may not be significantly limited as a result of our reorganization.

Liquidity and Capital Resources

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

(1)       As of December 31, 2009, total debt excludes our Senior Unsecured Notes due in 2017 which are recorded in Pre-petition liabilities subject to compromise.

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Overview and Outlook

As a result of filing for Chapter 11 bankruptcy protection, we have been accelerating our efforts to preserve existing liquidity, and are attempting to raise additional sources of liquidity and capital.  We have suspended construction of our expansion facilities at both Mt. Vernon, Indiana and Aurora, Nebraska.  We have also taken steps to reduce our fixed cost structure by rationalizing and reducing the size and scope of our distribution network.  We have taken and expect to take additional steps to preserve liquidity.

On April 7, 2009, certain of the Company’s bondholders entered into a term sheet for a first priority debtor-in-possession financing comprised of a term loan facility made available to certain of Aventine’s subsidiaries in a maximum aggregate principal amount of up to $30 million (the “DIP Facility”).  On May 5, 2009, the Bankruptcy Court overruled objections from the Debtors’ pre-petition secured lenders and approved the DIP Facility on a final basis.  The terms of the DIP Facility are described in further detail below under “Cash available under the DIP Facility.”

The amount of cash and borrowings available to us under our DIP facility at the end of the fourth quarter of 2009 was $15.0 million.

Although we suspended construction at both Aurora West and Mt. Vernon during the fourth quarter of 2008, we continue to have construction payment obligations to Kiewit.  On March 9, 2009, the Company received a notice from Kiewit cancelling the engineering, construction and procurement contracts for Aurora West and Mt. Vernon, referencing our failure to make a recent payment under the change order agreements dated December 31, 2008.  As a result, all remaining payments due to it and its sub-contractors totaling $23.2 million at December 31, 2009 are due and payable.  The breakdown of our recorded liability to Kiewit at December 31, 2009 is as follows:  $15.3 million is reflected in pre-petition liabilities subject to compromise and $7.9 million is reflected in other long-term liabilities on our consolidated balance sheet as of December 31, 2009.  We are currently engaged in discussions with Kiewit to negotiate a payment schedule that falls within the economic constraints with which we are currently operating.  We cannot give you any assurance that we will reach an agreement with Kiewit that works within our projected liquidity constraints.

We remain contractually obligated to complete the suspended plants at Aurora and Mt. Vernon and may incur significant penalties because of our failure to complete these facilities as previously scheduled.

Sources of Liquidity

Our principal sources of liquidity are cash, cash provided by operations, and cash available under our DIP facility.

Cash.  During 2009, cash increased by $29.2 million.  Cash and short-term investments as of December 31, 2009 and 2008 were $52.6 million and $23.3 million, respectively.

Cash provided by operations.  Net cash provided by operating activities in 2009 was $40.8 million, as compared to $35.6 million for 2008.

Cash available under the DIP Facility.  As of December 31, 2009, the Company had drawn $15 million of its $30 million DIP Facility.  The DIP Facility provides for a first priority term loan in a maximum aggregate principal amount of up to $30 million.  Proceeds of the DIP Facility can be used, among other things, to (i) fund the working capital and general corporate needs of the Debtors and the costs of the Bankruptcy Cases in accordance with an approved budget, and (ii) provide adequate protection, in

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accordance with the terms of the DIP Facility, to the pre-petition agent and pre-petition lenders under the Company’s existing credit facilities.  The DIP Facility bears interest at 16.5%.  The maturity date of the DIP Facility is April 6, 2010, or upon the occurrence of certain pre-defined events including emergence from bankruptcy.  The DIP Facility is secured by a super-priority administrative expense claim on our assets.  As of December 31, 2009, the Debtors are in compliance with the terms of its DIP Facility.  The Company accrues and pays interest expense on the DIP Facility in accordance with the Bankruptcy Court’s final order approving the DIP Facility.

Proposed Plan of Reorganization.  The proposed Plan of Reorganization provides that on the Effective Date we will complete a $105 million offering of 13% senior secured notes due 2015, the proceeds of which will, in part, be used to repay the DIP Facility in full.  In addition, the proposed Plan of Reorganization provides that, on or as soon as practicable after the Effective Date, we will close on a new credit facility with availability of up to $20 million.

Uses of Liquidity

Our principal use of liquidity during the year ended December 31, 2009 has been repayments of $24.4 million of borrowings under our secured revolving credit facility.

Off-Balance Sheet Arrangements

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

Contractual Obligations and Commercial Commitments

The following table provides a summary of our contractual obligations and commercial commitments as of December 31, 2009.  Former obligations of the Company for contracts rejected in bankruptcy are excluded from the table below.  These obligations are recorded in pre-petition liabilities subject to compromise at the amount the Company estimates will be allowed by the court as a bankruptcy claim.  Other non-current liabilities included in our Consolidated Balance Sheet that may not be fully disclosed below include accrued pension and post retirement costs.  Refer to Notes 16 and 17 of the Notes to the Consolidated Financial Statements.

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