Edgar Filing: AVENTINE RENEWABLE ENERGY HOLDINGS INC

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

[Mark One]

X Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2008

Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from _____________to _____________ ..

Commission file number 001-32922

AVENTINE RENEWABLE ENERGY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

Delaware	05-0569368
(State or other jurisdiction of	(IRS Employer Identification No.)
incorporation or organization)

120 North Parkway Drive
Pekin, Illinois	61554
(Address of principal executive offices)	(Zip Code)

(309) 347-9200
(Registrant’s Telephone Number, including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class:	Name of exchange on which registered:
Common Stock, $0.001 par value	New York Stock Exchange

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 ____ 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 ____ NO__X__

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 X NO____

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

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

Large accelerated filer ____

Accelerated filer X

Non-accelerated filer ____

(Do not check if a smaller reporting company)

Smaller reporting company ____

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES ____ 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, 2008 was approximately $507,948,246 based upon the closing price of the Common Stock reported for such date on the New York Stock Exchange.

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

Class	Outstanding as of March 12, 2008
Common Stock, $0.001 par value	42,970,988 Shares

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the annual meeting of stockholders to be held on May 27, 2009 are incorporated by reference into Part III.

FORM 10-K

YEAR ENDED DECEMBER 31, 2008

TABLE OF CONTENTS

Page No.

	PART I

Item 1.	Business	1
Item 1A.	Risk Factors	18
Item 1B.	Unresolved Staff Comments	34
Item 2.	Properties	35
Item 3.	Legal Proceedings	36
Item 4.	Submission of Matters to a Vote of Security Holders	36

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	67
Item 8.	Financial Statements and Supplementary Data	67
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	67
Item 9A.	Controls and Procedures	67
Item 9B.	Other Information	68

	PART III

Item 10.	Directors and Executive Officers of the Registrant and Corporate Governance	69
Item 11.	Executive Compensation	69
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	69
Item 13.	Certain Relationships and Related Transactions and Director Independence	69
Item 14.	Principal Accounting Fees and Services	69

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	70

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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.”). Our own production facilities produced 188.8 million gallons of ethanol in 2008 and 192.0 million gallons of ethanol in 2007. 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 2008 and 2007, we distributed 754.3 million gallons and 506.5 million gallons, respectively, of ethanol produced by others. Taken together, we marketed and distributed 936.0 million gallons of ethanol in 2008 and 690.2 million gallons of ethanol in 2007. For the years ended December 31, 2008 and 2007, this represents approximately 11% and 10%, respectively, of the total volume of ethanol sold in the U.S. We market and distribute ethanol to many of the leading energy companies in the U.S., including Royal Dutch Shell and its affiliates, Marathon Petroleum, BP, ConocoPhillips, Valero Marketing and Supply Company, Exxon/Mobil and Chevron. 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.

Because of the challenges facing the ethanol industry in general and us in particular, we expect to sharply decrease the number of gallons of ethanol we sell that are produced by others in 2009.

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 Statement of Financial Accounting Standards No. 141 (“SFAS 141”), Business Combinations.

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. We registered 9,058,450 shares of our common stock, all of which were sold in the offering at a gross per share price of $43.00 for an aggregate offering price of $389,513,350. Of the 9,058,450 shares sold, the Company sold 6,410,256 shares for an aggregate offering price of $275,641,008 and existing shareholders and management sold 2,648,194 shares for an aggregate offering price of $113,872,342.

We are a Delaware corporation organized in 2003, and are the successor to businesses engaged in the production and marketing of ethanol since 1981.

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. Information on our website should not be considered to be part of this annual report on Form 10-K.

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NYSE Certifications

Because our common stock is listed on the New York Stock Exchange (“NYSE”), our chief executive officer is required to make, and he has made, an annual certification to the NYSE stating that he was not aware of any violations by us of the corporate governance listing standards of the NYSE. Our chief executive officer made his annual certification to that effect to the NYSE as of June 2, 2008. In addition, we have filed, as exhibits to this Annual Report on Form 10-K, the certifications of our principal executive officer and principal financial officer under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 regarding the quality of our public disclosure.

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 two years has been largely driven by supply/demand fundamentals and the price of corn.

According to recent industry reports, approximately 98% of domestic ethanol is produced from corn fermentation as of December 31, 2008 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 9.2 billion gallons produced in 2008, with year-end 2008 production capacity of 12.5 billion gallons annually. Ethanol blends accounted for approximately 6.3% of the U.S. gasoline supply in 2008.

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 11.1 billion gallons in 2009 and 12.95 billion gallons in 2010. The mandated usage of renewable fuels increases to 36 billion gallons in 2022. The upper mandate for corn based ethanol is 15 billion gallons by 2015.

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

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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. However, as the price of oil began to fall rapidly in the second half of 2008, discretionary blending above mandated levels was no longer profitable and by December 31, 2008, discretionary blending had all but disappeared.

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. These 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. The consumption of ethanol above mandated amounts created an excess of RINS that are available to satisfy an obligated party’s blending requirements in the following year. 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.

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, a competing product to ethanol, making ethanol the primary clean air oxygenate currently used.

Octane enhancer. Ethanol, with an octane rating of 113, is used to increase the octane value of gasoline with which it is blended, thereby improving engine performance. It is used as an octane enhancer both for producing regular grade gasoline from lower octane blending stocks (including both reformulated gasoline blendstock for oxygenate blending (“RBOB”) and conventional gasoline blendstock for oxygenate blending (“CBOB”)), 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. 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 85% ethanol and 15% gasoline. 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 (as of December 31, 2008, only 1,922 gasoline stations across the U.S. sold E85, up from 1441 in 2007), and by the number of automobiles capable of using the fuel (approximately 6 million at December 31, 2008). However, the Energy Independence and Security Act of 2007 increased the incentives available to stations which install E85 capable equipment, while automobile manufacturers have significantly increased the number and models of cars able to use E85. These two factors point to a potential growth in the consumption of E85 in future years.

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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 undrinkable and thus not subject to the alcohol beverage tax. Historically, because the cost of denaturant was less than the price of ethanol, denaturant was blended with ethanol at a 4.96% level, the maximum allowed by law. However, beginning in the third quarter of 2007, as denaturant became more expensive than ethanol, we reduced the mix of denaturant we blend with ethanol to 1.96%, which was the minimum allowed by law. Beginning in 2009, Internal Revenue Service (“IRS”) regulations reduced the maximum permitted amount of denaturant for which the VEETC can be taken to 1.96%.

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, 2008, 2007 and 2006, we recovered 45.6%, 46.3% and 51.1%, 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 undrinkable 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, 2008, 2007 and 2006, we recovered 26.2%, 26.6% and 27.7%, 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 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. We source ethanol from the following three sources:

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

•

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

•

Ethanol we purchase 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 936.0 million, 690.2 million and 695.8 million gallons of ethanol for the years 2008, 2007 and 2006, respectively. Because of the challenges facing the ethanol industry in general and us in particular, we expect to sharply decrease the number of gallons of ethanol we sell that are produced by others in 2009.

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.’’ In October 2008, we purchased the remaining 21.58% of the Nebraska facility that we previously did not own through the issuance of 1 million shares of our common stock to the Nebraska Energy Cooperative and consolidated 100% of the results of Nebraska Energy, LLC. Prior to purchasing the remaining interest we did not own, we consolidated all of the assets, liabilities, revenue, expenses and cash flows of the Nebraska facility in our financial statements and presented the interest of the Nebraska Energy Cooperative as minority interest.

The production capacities listed for our facilities are for denatured ethanol gallons and assume a 4.96% denaturant blend, which was the standard rate used by the industry prior to 2007. We believe our competitors capacities are also stated as a denatured product and at a 4.96% denaturant blend rate. The denaturant we use is typically a low-grade gasoline. As gasoline prices began to rise significantly in 2007, we lowered the denaturant blend we used from 4.96% (which was the maximum allowed by law) to 1.96% (which is the minimum allowed by law). Beginning in 2009, IRS regulations reduced the maximum permitted amount of denaturant for which the VEETC can be taken to 1.96%. All references to our production capacity continue to assume a 4.96% denaturant blend rate as we believe the market has become accustomed to and accepted the capacities of our and our competitors plants at this blend level. 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 the years ended December 31, 2008 and 2007, our facilities have a combined total ethanol production capacity of 207 million gallons annually with corn processing capacity of approximately 77 million bushels per year at capacity. For the

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year ended December 31, 2006, our facilities only had a combined total ethanol production capacity of 150 million gallons annually with corn processing capacity of approximately 56 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 typically 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 94% of capacity for both 2008 and 2007 after adjusting for differences in denaturant blending levels.

For the years ended December 31, 2008, 2007, and 2006, we produced 188.8 million, 192.0 million, and 133.0 million gallons of ethanol, respectively, from our own facilities. Our equity production operations generate the substantial majority of our operating income or loss.

Marketing Alliance Production

Marketing alliance partners are third-party producers (including producers in which we may have a minority interest), who sell their ethanol production to us on an exclusive basis. Ethanol produced by our marketing alliance partners enables us to meet major ethanol consumer needs by providing us with a nationwide market presence and leveraging our marketing expertise and our distribution systems. Marketing alliance contracts require us to purchase all of the production from these facilities and sell it at contract or prevailing market prices. We are entitled to commissions on the sale of marketing alliance gallons in accordance with the terms of the marketing alliance contracts. Commission rates typically are 1% or less of the “netback” price. The netback price is the selling price of ethanol less a “cost recovery component”. The cost recovery component represents reimbursement to us for certain costs, including freight, storage, inventory carrying cost and indirect marketing costs. The purchase price we pay our marketing alliance partners is based on an average price at which we sell ethanol less the cost recovery component and commission. Revenue from marketing alliance gallons sold include the gross revenue from such sales and not merely the commissions earned because we (i) take title to the inventory, (ii) are the primary obligor in the sales arrangement with the customer, and (iii) assume all the credit risk. Since we are obligated to purchase all of the production of our marketing alliance partners, and since they typically operate at or near capacity, the volume of ethanol we purchase from our marketing alliance partners is driven by the capacity of their plants. See “Item 1 — Business — Marketing Alliances”.

For the years ended December 31, 2008, 2007 and 2006, we purchased 505.3 million, 395.0 million and 493.0 million gallons of ethanol, respectively, from our marketing alliance partners. In 2007, the volume of ethanol purchased from marketing alliance partners decreased due to the loss at the end of the first quarter of an alliance partner, which was offset somewhat by additions to our marketing alliance throughout the year. By year end 2007, we had essentially replaced all of the gallons caused by the loss of the alliance partner in the first quarter of 2007. The contribution to our operating income from the sale of marketing alliance gallons is relatively small.

For the past few years, our marketing business has been an important component of our business. Using the gallons we sourced from third parties, we were able to distribute significantly more ethanol than we could have produced from our own equity production, thereby giving us a greater marketing presence without having to make capital investments. However, with severely declining margins and general liquidity stress due to frozen credit markets, this model no longer works for our alliance partners or Aventine. As such, beginning in the fourth quarter of 2008, we have negotiated termination agreements with most of our marketing alliance partners and begun to rationalize our distribution network to primarily focus on sales of our equity production. Accordingly, we expect ethanol sourced from marketing alliance partners to decline sharply in 2009. As part of this new marketing strategy, we expect to see reductions in our fixed costs associated with our distribution network. See “Item 1 — Business — Marketing Alliances”.

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Purchase/Resale

We also purchase ethanol from third-party producers and marketers on both a spot basis and under contract. These transactions are 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 can be volatile and we can occasionally incur losses on these transactions.

For the years ended December 31, 2008, 2007 and 2006, we purchased for resale 249.0 million, 111.5 million and 68.2 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 is part of this rationalization process. We expect to significantly curtail the volume of ethanol sourced under this program in 2009. Our expectations are that the contribution to our operating income from purchase/resale transactions will continue to be limited for the foreseeable future.

By-Products

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

For the years ended December 31, 2008, 2007 and 2006, we generated approximately $128.5 million, $99.3 million and $54.7 million, respectively, of revenue from the sale of co-products and bio-products, allowing us to recapture approximately 35.9%, 36.7% and 44.7% of our corn costs, respectively, in each of these years. Co-product returns, as a percentage of corn costs, decreased in 2008 due to the record high prices for corn. 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.

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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, 2008, 2007 and 2006, ethanol sales represented 92.5%, 91.3% and 95.4%, respectively, of our total revenue.

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, 2008, 2007 and 2006, co-products represented 5.2%, 5.7% and 2.9%, respectively, of our total revenue.

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, 2008, 2007 and 2006, bio-products represented 0.5%, 0.6% and 0.6%, respectively, of our total revenue.

Competition

As of December 2008, there were 125 producers operating 193 ethanol plants in the U.S. The top ten producers accounted for approximately 46.6%, 54.3%, and 44.4% of total industry capacity for the years 2008, 2007, and 2006, respectively. 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). In 2008, imports of ethanol into the U.S. were not significant to the U.S. domestic marketplace. In the past, occasions of significant ethanol imports have had a negative effect on ethanol prices.

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. Continued increases in the price of corn, or 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.

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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 the current poor operating environment for ethanol production, 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 which were the largest outflows of cash. 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 which include staff reductions and other such measures.

Although we are actively pursuing a number of liquidity alternatives, including seeking additional debt and equity financing and a potential sale of all or part of the company, there can be no assurance we will be successful. If we cannot obtain sufficient liquidity in the very near-term, we may need to seek to restructure under Chapter 11 of the U.S. Bankruptcy Code.

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 are currently undertaking a rationalization of our existing terminal and distribution system. As part of this rationalization process, we expect to significantly reduce the number of terminals where we maintain a presence, eliminate or reduce our use of barges in the transportation of ethanol, and reduce the number of railcars we employ to transport ethanol. We anticipate these steps will significantly reduce the fixed costs of maintaining such assets. Our belief is that this strategy will allow us to be able to increase our participation in the marketing and distribution of ethanol in the U.S. when ethanol demand once again begins to accelerate.

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.

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Marketing Alliances

Sourcing ethanol from marketing alliance partners 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. Under marketing alliance contracts, we agreed to purchase all fuel-grade ethanol produced by our marketing alliance partners. The purchase price we paid marketing alliance partners was based on an average price at which we sold ethanol less a cost recovery component and commission. The cost recovery component represented reimbursement to us for certain costs, including freight, storage, inventory carrying cost and indirect marketing costs. In addition, our marketing alliance partners paid us a commission which is generally 1% or less of the netback price. The netback price was the selling price of ethanol less the cost recovery component. Our marketing alliance contracts typically had two year terms and renewed automatically for additional one year terms unless either party elected to terminate in advance. During the years ended December 31, 2008, 2007 and 2006, we purchased 505.3 million, 395.0 million and 493.0 million gallons, respectively, of ethanol produced by our marketing alliance partners. In 2007, the volume of ethanol purchased from marketing alliance partners decreased due to the loss at the end of the first quarter of an alliance partner, which was offset somewhat by additions to our marketing alliance throughout the year. By year end 2007, we had essentially replaced all of the gallons caused by the loss of the alliance partner in the first quarter of 2007.

For the past few years, our marketing business has been an important component of our business. Using the gallons we sourced from third parties, we were able to distribute significantly more ethanol than we could have produced from our own equity production, thereby giving us a greater marketing presence without having to make capital investments. However, with severely declining margins and general liquidity stress due to frozen credit markets, this model no longer works for our alliance partners or us. As such, beginning in the fourth quarter of 2008, we have negotiated termination agreements with most of our marketing alliance partners and begun to rationalize our distribution network to primarily focus on sales of our equity production. We expect ethanol sourced from marketing alliance partners to decline sharply in 2009. As part of this new marketing strategy, we expect to see reductions in our fixed costs associated with our distribution network.

The following table presents our marketing alliance status as of December 31, 2008:

Name	Location	Annual Capacity (millions of gallons)
Status of Marketing Alliance Plants at 12/31/08
Aberdeen Energy, LLC (1)	Mina, SD	100
Ace Ethanol, LLC * (1)	Stanley, WI	41
Agri Energy, LLC	LuVerne, MN	21
E Energy Adams (1)	Adams, NE	50
E3 Biofuels (2)	Mead, NE	24
Ethanol Grain Processors* (1)	Obion, TN	100
Glacial Lakes Energy (1)	Watertown, SD	100
Granite Falls Energy, LLC * (1)	Granite Falls, MN	52
Husker Ag, LLC (1)	Plainview, NE	67
Indiana Bio-Energy, LLC* (1)	Bluffton, IN	100
Redfield Energy, LLC (1)	Redfield, SD	50
Reeve Agri-Energy	Garden City, KS	12
Xethanol Biofuels (3)	Blairstown, IA	5
		722
Marketing Alliance Plants Financed and Under Construction
Panda Energy (4)	Hereford, TX	115

Total Marketing Alliances at 12/31/08		837

* Denotes marketing alliance partners in which we have made equity investments. Subsequent to December 31, 2008, we sold our equity interests in Ace Ethanol, LLC and Granite Falls Energy, LLC.

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(1) Denotes marketing alliance agreements terminated or otherwise repudiated subsequent to December 31, 2008.

(2) E3 Biofuels filed for Chapter 11 bankruptcy protection on November 30, 2007 and is currently not producing ethanol.

(3) Xethanol Biofuels ceased producing ethanol in May 2008. On October 27, 2008, Xethanol merged with Global Energy Holdings Group, Inc. Global Energy Holdings Group, Inc. retains ownership of the Blairstown, IA plant which has been idle since May 2008.

(4) Panda Energy filed for Chapter 11 bankruptcy protection on January 23, 2009, prior to bringing its facility on-line.

We have 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 IBE prior to its acquisition by Green Plains Renewable Energy (“GPRE”). Investments made by our predecessor company in one ethanol plant prior to May 31, 2003 were written down to zero as part of the purchase price allocation upon the acquisition of the Company by MSCP.

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 publically held company whose shares are traded on the NASDAQ national market, and our $5.0 million original investment was converted to 365,999 shares of GPRE stock. On October 15, 2008, we recorded a loss of $2.8 million on the exchange and reduced the value of our investment from $5.0 million to $2.2 million, which was the market price of the GPRE shares at that date. As our investment in GPRE shares is considered an available for sale investment in accordance with Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities (“SFAS 115”), we recognized an other than temporary loss of $1.5 million on December 31, 2008. In making our determination that the loss in GPRE stock was other than temporary, we considered our lack of ability and intent to hold this security to recover its value given our current liquidity situation. The market value of our investment in GPRE at December 31, 2008 based upon the closing price of GPRE stock on the last trading day of 2008 was $0.7 million.

Subsequent to December 31, 2008, we sold our interests in Ace Ethanol, LLC and Granite Falls Energy LLC, recording gains totaling $1.0 million. After taking into account the sale of the two equity interests which occurred in January 2009, we continue to have investments of 365,999 shares of common stock in GPRE and 131,000 membership shares in Advanced BioEnergy, LLC.

Distribution and Logistics

Our extensive logistics system historically had been a key component to our customer service commitment. We believed that this network provided us with a competitive advantage with customers. However, due to severely declining margins and general liquidity stress due to frozen credit markets, we are significantly reducing 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 subsequent to year-end have negotiated termination of nearly all of them. We received termination settlements of $14.1 million. Accordingly, we have also undertaken a strategy to rationalize our distribution and logistics system to focus primarily on our equity production. We expect this rationalization process to improve our efficiency, and to significantly reduce or eliminate our presence in numerous terminals, the amount of ethanol transported via barge, and the number of railcars we use to

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distribute ethanol. At December 31, 2008, we had signed agreements for leased terminal capacity at 57 terminal locations, with 55 of these terminals in operation as of that date. Subsequent to December 31, 2008, we have subleased or assigned the majority of our railcar, barge and terminal leases. On sublease arrangements, we remain secondarily liable to the lessor. Our intent is to align our distribution network in relation to production volumes from our equity-owned ethanol production facilities, and for this distribution network to have a cost structure that is comprised of minimal fixed cost commitments and is operated primarily on a variable cost basis by March 31, 2009.

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. As a result of the down-sizing of our marketing alliance business, we will lose economies of scale we previously benefited from. See ‘‘Item 1 — Business — Marketing Alliances.’’

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 from 2015 through 2022.

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

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lowered to $0.54 per gallon with a 2.5% ad valorem duty and was not adjusted completely in sync 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 2006, there were also significant imports of ethanol from non-CBI countries. Although these imports were subject to the tariff, significant increases in the price of ethanol in 2006 made the importation of ethanol from non-CBI countries profitable, in spite of the tariff. There were no material imports of ethanol into the U.S. in 2008 or 2007. 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.

Customers

We focus on providing exceptional customer service and, as a result, have had relatively little customer turnover. The substantial majority of our customer base has purchased ethanol from us for over five years (including our predecessor companies). In 2008, 2007 and 2006, our 10 largest customers accounted for approximately 50%, 67% and 75%, respectively, of our consolidated ethanol sales volume. None of our customers in 2008 represented more than 10% of our consolidated net sales volume.

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Pricing and Backlog

Generally, ethanol delivered to customers is 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 believes its pricing strategies, in conjunction with the rapid turnover of its inventory, provide a natural hedge against changes in the market price of ethanol.

As of December 31, 2008, we had contracts for delivery of ethanol totaling 143.6 million gallons through December 2009. These commitments were for 4.2 million gallons at an average fixed price of $2.41 per gallon, 4.9 million gallons at an average spread to wholesale gasoline of a negative $0.55 per gallon (based upon the NYMEX, Chicago and NY harbor indices), and 134.5 million gallons at spot prices (using various Platt, OPIS and AXXIS indices).

Raw Materials and Suppliers

Our principal raw material is #2 yellow corn. In 2008, 2007 and 2006, we purchased approximately 71.4 million, 71.9 million and 51.0 million bushels of corn, respectively. Our purchases of corn beginning in 2007 increased significantly as a result of the addition of the Pekin dry mill which began grinding corn early in 2007.

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 (“CBOT”) price as a benchmark. Corn is delivered to our facilities via truck through local distribution networks and by rail.

Research and Development

Our research and development efforts have primarily been managed from our corporate office in Pekin, Illinois and are conducted at our Pekin wet mill facility. We have, in the past, participated in this research with other outside entities, including both Purdue University and the USDA’s National Center for Agriculture Utilization Research in Peoria, Illinois. Our research and development efforts consist of research into cellulosic ethanol (cellulosic plant biomass representing an untapped potential feedstock for the generation of fuel ethanol from renewable resources). Our primary objective of this research is to develop and scale up an efficient and economical pretreatment process for corn fiber and corn stover (the stalks and husks left over after harvest). We are committed to continuing research into the potential benefits associated with cellulosic ethanol.

Research and development expense was approximately $0.1 million in 2008, $0.3 million in 2007 and $0.2 million in 2006.

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Patents and Trademarks

We own a number of trademarks and patents within the U.S. In addition, we currently have one patent pending with the United States Patent and Trademark Office. 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, 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. 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. 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, 2008. 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 spills or 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.

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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 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. 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. In particular, Illinois and five other Midwestern states have entered into the Midwestern Greenhouse Gas Reduction Accord, a program which directs participating states to develop a multi-sector cap-and-trade mechanism to help achieve reductions in greenhouse gases, including carbon dioxide. It is possible this program could require carbon dioxide emissions reductions from our Pekin, Illinois plants, which could result in significant costs. In addition, it is possible that other states in which we conduct or plan to conduct business, including Nebraska and Indiana, could join this accord or that federal, state or local regulators could require other costly carbon dioxide emissions reductions or offsets.

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’’ and “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental Matters.”

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Employees

At December 31, 2008, we had a total of 346 full-time equivalent employees. Approximately 48% of our 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. As a whole, we believe our relations with our employees are good.

Our existing contract with the United Steelworkers International Union, Local 7-662 expires in October 2009. While we generally believe our relations between the Company and Local 7-662 are good, 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.

Item 1A. Risk Factors

There is substantial doubt as to our ability to continue as a going concern. We need additional financing or capital which may be unavailable or costly.

As a result of ethanol industry conditions that have negatively affected our business, we do not currently have sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. In particular, we do not expect to have adequate liquidity to satisfy the $15 million interest payment due on April 1, 2009 on our outstanding senior unsecured 10% fixed-rate notes or the $24.4 million due to our EPC contractor, Kiewit Energy Company (“Kiewit”). In addition, we are currently in default under our outstanding 10% fixed-rate notes which permits the holders thereof to accelerate the $300 million principal amount thereof upon 60 days notice. The default under our 10% fixed rate notes constitutes an event of default under our secured revolving credit facility, which has been waived by lenders under our secured revolving credit facility until April 15, 2009. As a result, our 2008 financial statements include an explanatory paragraph by our independent registered public accounting firm describing the substantial doubt as to our ability to continue as a going concern.

As of March 12, 2009, $22.2 million in letters of credit and $16.5 million in revolving loans were outstanding under the amended secured revolving credit facility. After giving effect to the recent amendment to our secured revolving credit facility, we had $0.7 million of cash and $6.6 million of additional borrowing availability thereunder as of such date. All of our cash receipts are automatically applied to reduce amounts outstanding under our amended secured revolving credit facility and to cash collateralize our letters of credit. As we continue to reduce the number of gallons of ethanol we sell and hold in inventory, working capital available to support borrowings under our secured revolving credit facility will reduce proportionately.

The amendment to our secured revolving credit facility requires us to successfully complete an exchange offer of our outstanding senior unsecured 10% fixed-rate notes for a like principal amount of a new series of “pay-in-kind” notes. We expect the “pay in kind” notes to (i) require no cash interest prior to April 1, 2010, (ii) require an increase in the interest rate to 12% per annum and (iii) grant a second lien on substantially all of our assets which must be contractually subordinated to the obligations under our secured revolving credit facility. In addition, to encourage holders of our senior unsecured 10% fixed-rate notes to participate in the exchange offer, we expect to need to offer the holders of our senior unsecured 10% fixed-rate notes 8.4 million shares of our common stock (representing approximately 19.9% of our currently outstanding shares of common stock). There can be no assurances, however, that the required percentage or any holders of the senior unsecured 10% fixed-rate notes will agree to an exchange on these terms or at all. Failure to have the holders of 80% of the existing senior unsecured 10% fixed-rate notes commit to participate in the exchange by March 31, 2009 or the failure to consummate the exchange for

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90% of the existing senior unsecured 10% fixed-rate notes by April 15, 2009 would be an event of default under our secured revolving credit facility.

Even if we are successful with the senior unsecured 10% fixed-rate note exchange offer, we do not expect to have sufficient liquidity to meet anticipated working capital, debt service and other liquidity needs during the current year unless we experience a significant improvement in ethanol margins or obtain other sources of liquidity. Based on the current spread between corn and ethanol prices, the industry is operating at or near breakeven cash margins. We experienced negative gross margins during the second half of 2008 and expect negative gross margins to continue through the first quarter of 2009 due in part to our fixed price obligations to purchase corn and natural gas at above current market prices. The current spread between ethanol and corn prices cannot support the long-term viability of the U.S. ethanol industry in general or us in particular.

In addition, although we suspended construction at both Aurora West and Mt. Vernon during the fourth quarter, 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 (EPC) 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 $24.4 million at February 28, 2009 are due and payable. 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 existing liquidity constraints.

Because our obligations to Kiewit are past due, the liens securing these obligations violate the terms of our 10% fixed rate notes and constitute a default thereunder. Unless such default is cured through payment, the release of the liens, a negotiated resolution or otherwise, the holders of our 10% fixed rate notes may accelerate the $300 million principal amount thereof upon 60 days notice. In addition, the default under our 10% fixed rate notes constitutes an event of default under our secured revolving credit facility, which is our only current source of liquidity. We have obtained a waiver from the lenders under our secured revolving credit facility until April 15, 2009. Any foreclosure on such liens by Kiewit would constitute an event of default under our amended secured revolving credit facility that is not covered by the waiver.

We remain contractually obligated to complete the suspended plants at Aurora and Mt.Vernon as well as an additional plant at Mt. Vernon capable of producing 110 million gallons of ethanol annually and may incur significant penalties because of our failure to complete these facilities as previously scheduled.

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 113 million gallon plant adjacent to our Nebraska facility (using commercially reasonable best efforts to obtain a permit for 226 million gallon capacity) and a two-phase 226 million gallon plant in Mount Vernon, Indiana and may incur significant penalties because of our failure to complete these facilities as previously scheduled.

We may be subject to material penalties if we do not timely complete the initial 113 million gallon “phase I” of the Aurora Expansion or either the initial “phase I” or the second 113 million gallon “phase II”

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of the Mt. Vernon expansion. If phase I of the Aurora plant is not completed and fully operational by July 1, 2009 we will be responsible for liquidated damages of $138,889 per month (up to a maximum of $5 million) until the plant is fully operational. We have suspended construction at Aurora indefinitely and do not expect to complete it by July 1, 2009. Accordingly, we expect to be required to pay the stipulated liquidated damages. If we are unable to or otherwise do not pay these damages, the counterparty has 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 Port Commission to provide additional flexibility as to the timing of the phase II expansion at Mt. Vernon. This lease, as amended, requires substantial completion of phase I (an initial 110 million gallons of capacity) by October 1, 2009 and substantial completion of phase II (an additional 110 million gallons of capacity) by January 1, 2011, subject in the case of phase II to specified extension rights. If we do not achieve these milestones, the State may, subject to specified cure rights, take over construction and complete the facility at our expense. In addition, if we fail to achieve these milestones we will, subject to specified cure rights or our ability to negotiate an extension, be in default under our lease and the State may also, at its election, (i) without terminating the lease, re-let the premises to a third party and charge us for any necessary repairs and alterations, (ii) without terminating the lease, require us to pay all amounts we are obligated to pay under the lease as they become payable, less any amount received from any re-letting of the premises or (iii) terminate the lease. If the State terminates the lease it can require that we pay liquidated damages in the amount by which the lease payments we are obligated to make under the lease exceed the fair and reasonable rental value of the premises, each discounted to present value (but in no event being less than two years of basic rent and minimum guaranteed wharfage under the lease). In addition, upon any termination or expiration of the lease, the State does not have to pay us for the value of the plant or any other improvements that we made to the premises and can require us to restore the leased premises to their original condition at our cost and expense. We have suspended construction of phase I at Mt. Vernon for the foreseeable future and have not commenced construction of phase II. Accordingly, we are engaged in negotiations with the Indiana Port Commission. If we are unable to reach an agreement with the Indiana Port Commission, they may exercise any of the foregoing remedies which could have a material adverse effect on our financial condition and results of operations and require us to seek to restructure under Chapter 11 of the U.S. Bankruptcy Code.

On March 9, 2009, we received a notice from our EPC contractor, Kiewit, cancelling the EPC contracts for phase I of Aurora West and Mt. Vernon, referencing our failure to make a recent payment. Accordingly, we no longer have EPC contracts for the completion of Aurora West or Mt. Vernon and do not have any recourse against Kiewit for design or construction defects or performance guarantees under those EPC contracts.

Our liquidity could be adversely impacted in the event our bank was to impose material reserve requirements under our secured revolving credit facility.

Our secured revolving credit facility allows the agent for this facility to arbitrarily impose reserve requirements in order to protect its collateral position. Our operations are dependant upon our ability to access liquidity under this facility. As we rationalize our ethanol sourcing and distribution network, we are quickly and significantly reducing the amount of collateral available for borrowing. As a result, the administrative agent for our secured revolving credit facility may become concerned as to the adequacy or sufficiency of their collateral. Should the agent for our secured revolving credit facility impose reserves which limit or reduce the availability under this facility, the negative impact on our liquidity could be significant, which could materially adversely affect our business.

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Our strategic plan includes reducing the number of terminals in which we have lease commitments and reducing the number of railcars under lease through either re-assignment of railcar leases or through sub-leasing. Should we be unsuccessful in negotiating the termination of these obligations without material penalties, or should we not receive payments under these sub-lease agreements as expected, our business could be materially adversely affected.

Our fixed commitment for the leasing of terminals and railcars is substantial. Our business plan for 2009 includes significantly reducing the number of terminals and railcars we lease, including through assignments and subleases. Although we believe we will be able to negotiate the termination or sublease of these leases without any material expense or penalties, there can be no assurance that we will be successful. In addition, to the extent that we sublease these terminals and railcars, we will remain responsible in the event that any sublessee fails to fulfill its commitments. Should we be unsuccessful in achieving these expectations, we may be liable for significant damages. Should we be unsuccessful in negotiating the termination of these obligations without material penalties, our business could be materially adversely affected.

Our common stock may be delisted from the New York Stock Exchange.

Our common stock is currently listed on the New York Stock Exchange (the “NYSE”). We may fail to comply with the continued listing requirements of the NYSE, which may result in the delisting of our common stock. The NYSE rules require, among other things, that the minimum market capitalization of a listed company’s common stock be at least $15 million (temporarily reduced from the $25 million requirement through June 30, 2009). Since February 17, 2009, we have not met that requirement. If we fail to meet that requirement for 30 consecutive trading days we will be subject to delisting by the NYSE. As of March 6, 2009, we have not met the 30 consecutive trading day requirement. In addition, the continued listing requirements of the NYSE require that the minimum trading price of our common stock be at least $1.00. The minimum trading price requirement has been suspended until June 30, 2009. We have not satisfied the minimum trading price requirement since November 14, 2008. If we failed to comply with the minimum listing price requirement as of or after June 30, 2009 and were unable to cure such defect within the six months following the receipt of any notice from the NYSE regarding our failure to achieve the minimum listing price of our common stock, the NYSE might delist our common stock. Additionally, we may receive a notice of delisting from the NYSE due to our failure to exceed the amended 30 consecutive trading day market capitalization standard. Delisting would have an adverse effect on the liquidity of our common stock and, as a result, the market price for our common stock might become more volatile. Delisting could also make it more difficult for us to raise additional capital.

The spread between ethanol and corn prices can vary significantly and our profitability from gallons produced at our facilities is dependent on this spread.

Gross profit on gallons produced at our facilities, which accounts for the substantial majority of our operating income or loss, is principally dependent on the spread between ethanol and corn prices. We experienced negative gross margins in the second half of 2008 and expect negative gross margins to continue at least through the first quarter of 2009 due in part to our fixed price obligations to purchase corn and natural gas at or above current market prices. The U.S. ethanol industry generally is operating at or near breakeven gross margins. The current spread between ethanol and corn prices cannot support the long-term viability of the U.S. ethanol industry in general or us in particular.

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. In addition, there is a significant amount of ethanol capacity currently under construction. According to the RFA, as of December 2008, approximately 2.1 billion

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gallons per year of production capacity is currently under construction. Despite demand growth, increased penetration in new markets, and a government mandate, U.S. production capacity increased by 42.3% in 2008 while demand increased by only 40.7%. In addition, at the end of 2008, there was approximately 2 billion gallons of production capacity shut-in. Demand for ethanol may not increase as quickly as expected or to a level that exceeds supply, or may not increase at all. As a result of the excess ethanol capacity in the second half of 2008 the industry was operating at or near breakeven gross margins. If the ethanol industry continues to have excess capacity, it could have a significant adverse impact on our results of operations, cash flows and financial condition.

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, 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 2008, the top ten domestic producers accounted for approximately 46.6% 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.

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 2008, we purchased approximately 71.4 million bushels of corn at a cost of $358.4 million, which comprised about 71% of our total cost of production. In 2008, our average corn cost ranged from a low of $4.26 per bushel in January 2008 to a high of $6.07 per bushel in August 2008. 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 vast increase in U.S. ethanol capacity under construction could outpace increases in corn production, which may further increase corn prices and significantly 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.

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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 take hedging positions in the corn futures markets. However, these hedging transactions also involve risk to our business. See ‘‘Item 1A –Risk Factors — We may engage in hedging and 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 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

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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. 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. By 2015, approximately half of the renewable fuels required to meet the RFS must be non-corn-based ethanol and by 2021, nearly all must be non-corn-based ethanol. 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 will be adversely affected.

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

Imported ethanol is generally subject to a $0.54 per gallon tariff and a 2.5% ad valorem tax that was designed to offset the $0.45 per gallon ethanol subsidy currently available under the federal excise tax incentive program for refineries and blenders that mix ethanol with their gasoline. 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.

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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, 2008. 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.

Federal and state environmental authorities have been investigating alleged excess VOC emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities. The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility. If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar matter at our Nebraska facility due to the larger size of the Illinois wet mill facility. 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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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 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. For example, we expect our negative gross margins to continue at least through the first quarter of 2009 due in part to our fixed price obligations to purchase corn and natural gas at or above current market prices. There can be no assurance that additional losses will not occur. Alternatively, we may choose not to engage in hedging transactions in the future. As a result, our results of operations may be adversely affected during periods in which corn and/or natural gas prices increase.

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.

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

We rely upon third parties for our supply of natural gas which is consumed in the production of ethanol. 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 nine year period from 2000 through December 31, 2008, based on the New York Mercantile Exchange, or NYMEX, daily futures data, has ranged from a low of $1.63 per MMBtu in 1999 to a high of $15.38 per MMBtu in December 2005. We currently use approximately 3.4 million MMBtu’s of natural gas annually, depending upon business conditions, in the manufacture of our products. Our usage of natural gas will increase with the planned expansion of our production facilities.

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

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

At any given time, our 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. These contracts typically provide for delivery from one month to one year later. As of December 31, 2008 we had contracted to sell 4.2 million gallons of ethanol at an average fixed price of $2.41. We have also contracted to sell 4.9 million gallons of ethanol at an average negative spread of $0.55 per gallon to the wholesale value of gasoline at the time of delivery and 134.5 million gallons of ethanol at the spot price at the time of delivery. These contracts provide for delivery throughout 2009, but they are heavily weighted towards the first quarter of 2009.

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 marketing alliance partners and our purchase/resale transactions, along with our own cost to produce ethanol. We occasionally increase our inventory, in order to profit when we believe market prices will 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 may recognize income from cancellation of indebtedness as a result of the senior unsecured note exchange offer.

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Except as described in the next paragraph, if the exchange offer for our 10% fixed rate notes is consummated we will recognize, in the year of the exchange, income from cancellation of indebtedness (“COD”) as a result of the exchange to the extent that the fair market value of the equity shares of our common stock and the issue price of the new notes, such issue price being determined based on the fair market value of the new notes, is less than the principal amount of, and accrued but unpaid interest on, the outstanding senior unsecured notes. Although the precise amount of COD income that we will realize cannot be determined until the date of the exchange, based on current estimates we believe that the amount of COD income we could realize will be approximately $260 million.

There are two exceptions to the current recognition of COD income that may apply to us. Under the “insolvency” exception, we will not be required to realize COD income on the exchange to the extent that, immediately prior to the exchange, we are “insolvent” for tax purposes (generally, the extent to which the fair market value of our assets is less than our liabilities). To the extent COD income is excluded under the insolvency exception, we will be required to reduce certain of our tax attributes (principally, the tax basis in our assets). Among other things, this would have the effect of reducing our future depreciation deductions. The American Recovery and Reinvestment Act of 2009 (“ARRA”) added a second exception to the immediate realization of COD income, which would permit us to elect to defer the current recognition of any COD income resulting from the exchange, and instead recognize any such income ratably over a five-year period beginning in 2014. If we make this election, we would be required to defer the deduction of all or a substantial portion of any “original issue discount” (“OID”) that accrues on the new notes prior to 2014, and would be allowed to claim such deferred deductions only ratably over the same five-year period. If we make this election, the insolvency exception described above would not apply. ARRA also added an exception to the rules that generally apply to “applicable high yield discount obligations,” which will permit us to deduct any OID on the new notes without regard to such rules, which would otherwise have the effect of disallowing a substantial portion of our OID deductions on the new notes.

We are currently considering whether to make the election described in the preceding paragraph or to rely on the insolvency exception in the event that we successfully complete the senior unsecured note exchange offer. Our decision will depend on, among other things, the extent to which we believe we would be insolvent for tax purposes at the time of the exchange and estimates of our future taxable income or loss depending on whether we make the election described above or rely on the insolvency exception. Regardless of whether we make the election or rely on the insolvency exception, we do not expect the exchange, if successfully completed, to result in a material current cash tax liability for the company.

Our ability to use certain of our tax attributes in the future may be limited.

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 could experience an ownership change in the future as a result of changes in the ownership of our stock or future issuances of our stock, including pursuant to the senior unsecured note exchange offer.

We currently have a substantial net unrealized built-in loss in our assets. 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

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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.

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 conclude 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.

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

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the United States, biobutonal 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, 2008, approximately 48% 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.

Our existing contract with the United Steelworkers International Union Local 7-662 expires in October 2009. While we generally believe our relations between the Company and Local 7-662 are good, 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.

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 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. For example, Metalmark has and may in the future make significant investments in other companies, some of which may be competitors. Metalmark is not obligated to advise us of any investment or business opportunities of which they are aware, and they are not restricted or prohibited from competing with us.

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

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receive for these products may not rise as corn prices rise, thereby lowering our cost recovery percentage relative to corn.

Due to recent and planned industry increases in U.S. dry mill ethanol production, the production of DDGS in the U.S. has increased dramatically, and this trend may continue. This may cause DDGS prices to fall in the U.S., unless demand increases or other market sources are found. To date, demand for DDGS 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.

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.

The requirements of complying with the Exchange Act and the Sarbanes-Oxley Act may strain our resources and distract management.

We are subject to the reporting requirements of the Exchange Act, and the Sarbanes-Oxley Act, including Section 404. These requirements may place a strain on our systems and resources. The Exchange Act requires that we file annual, quarterly and current reports with respect to our business and financial condition. The Sarbanes-Oxley Act requires that we maintain effective disclosure controls and procedures, corporate governance standards and internal controls over financial reporting. Pursuant to Section 404 of the Sarbanes-Oxley Act, our management has delivered a report that assesses the effectiveness of our internal control over financial reporting. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight may be required as we have to devote additional time and personnel to legal, financial and accounting activities to ensure our ongoing compliance with public company reporting requirements. This may cause management’s attention to be diverted away from other business concerns, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, in order to remain in compliance, we may need to hire additional accounting and financial staff with appropriate public company experience and technical accounting knowledge, and might not be able to do so in a timely fashion.

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;

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

·	raw material supply disruptions;

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

·	transportation disruptions.

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

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 other qualified personnel, particularly executive management. The loss of the services of any of our key employees or the failure to attract or retain other qualified personnel, domestically or abroad, could have a material adverse effect on our business or business prospects.

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

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

We and our subsidiaries are not contractually restricted from incurring substantial additional indebtedness. This could further exacerbate the risks that we and our subsidiaries face.

We and our subsidiaries are not contractually restricted from incurring substantial indebtedness in the future. Our planned capacity increases require us to incur substantial additional indebtedness. If new debt is added, the related risks that we and our subsidiaries now face could intensify.

Our stock price may be volatile.

The market price of our common stock could be subject to significant fluctuations. Among the factors that could affect our stock price are:

·	our common stock could be delisted by the NYSE;

·	quarterly variations in our operating results;

·	changes in revenue or earnings estimates or publication of research reports by analysts;

·	failure to meet analysts’ or our own revenue or earnings estimates;

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·	speculation in the press or investment community;

·	strategic actions by us or our competitors, such as acquisitions or restructurings;

·	the impact of the risks discussed herein and our ability to react effectively to those risks;

·	limited trading volume of our common stock;

·	a change in technology that may add to production costs;

·	actions by institutional stockholders;

·	general market conditions; and

·	domestic and international economic factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

Limited trading volume of our common stock may contribute to its price volatility.

Our common stock is traded on the New York Stock Exchange. For the period of January 2, 2008 to December 31, 2008, the average daily trading volume of our common stock as reported by Bloomberg L.P. was approximately 818,000 shares. It is uncertain whether a more active trading market in our common stock will develop. If a significant number of analysts were to discontinue coverage of our common stock, our trading volume may be further reduced. As a result, relatively small trades could potentially have a significant impact on the market price of our common stock, which could increase the volatility and depress the price of our stock.

Future sales of our common stock may cause the price of our common stock to decline or impair our ability to raise capital in the equity markets.

In the future, we may sell additional shares of our common stock in public or private offerings. Shares of our common stock are also available for future sales pursuant to stock options and/or restricted stock that we have granted to certain employees and directors, and in the future we may grant additional stock options and/or restricted stock to our employees and directors. Sales of substantial amounts of common stock, or the perception that such sales could occur, may adversely affect prevailing market prices for shares of our common stock and could impair our ability to raise capital through future offerings.

Provisions in our charter documents, Delaware law and in other agreements may delay or prevent an acquisition of Aventine, which could decrease the value of our common stock.

Provisions in our amended certificate of incorporation and bylaws, Delaware corporate law and our stockholder rights plan may make it more difficult and expensive for a third party to pursue a tender offer, change in control or takeover attempt without the consent of our board of directors. These provisions include a classified board of directors, removal of directors only for cause, and the inability of stockholders to act by written consent or to call special meetings. Although we believe these provisions provide for an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our board of directors, these provisions apply even if the offer may be considered beneficial by some stockholders.

In addition, under the indenture governing our senior unsecured 10% fixed-rate notes, in the event a change in control occurs, we may be required to repurchase all of our outstanding senior unsecured 10% fixed-rate notes at 101% of their original aggregate principal amount plus accrued interest. A change in control, without an appropriate waiver or amendment, would also result in an event of default or amortization event under our secured revolving credit facility.

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Item 1B. Unresolved Staff Comments

There are no unresolved comments.

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Item 2. Properties

We have current capacity to produce 207 million gallons of ethanol per year. 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:

Location	Owned/ Leased	Property Size (acres)	Capacity (in millions of gallons)	Mill Type	Year Opened	Number of Production Related Employees at Dec. 31, 2008	Description
Pekin, IL	Owned	83	100	Wet	1981	204	Produces fuel-grade ethanol, as well as co-products and bio-products consisting of corn gluten feed, corn gluten meal, condensed corn distillers with solubles (both wet and dry), corn germ, carbon dioxide and Kosher and Chametz free brewers’ yeast.
Pekin, IL	Owned	11	57	Dry	2007	17	Produces fuel-grade ethanol, as well as co-products consisting of dried distillers grains, wet distillers grains and carbon dioxide.
Aurora, NE	Owned	30	50	Dry	1995	32	Produces fuel-grade ethanol, as well as co-products consisting of dried distillers grains, wet distillers grains and carbon dioxide.

Facilities Where Construction Has Begun But Is Currently Suspended:

Location	Owned/ Leased	Capacity (in millions of gallons)	Mill Type	Property Size (acres)	Description
Aurora, NE	Owned	113	Dry	86	The Company purchased this property for the construction of ethanol production facilities capable of producing 226 million gallons of denatured ethanol annually. Construction began but has been suspended on phase I with an annual production capability of 113 million gallons of denatured ethanol annually.
Mount Vernon, IN	Leased (1)	113	Dry	116	The Company leases the land underlying this property from the State of Indiana with the obligation of developing and operating a 226 million gallon ethanol facility. Construction began but has been suspended on phase I with an annual production capability of 113 million gallons of denatured ethanol annually.

Land for Future Expansion:

Location	Owned/ Leased	Property Size (acres)	Description
Pekin, IL	Owned	26	The Company has owned this property since 2003 and may develop and operate another 113 million gallon ethanol dry mill facility at this location.

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(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.

Item 3. Legal Proceedings

Our facilities and operations are subject to extensive environmental laws and regulations, and we are currently involved in various proceedings relating to environmental matters, 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.

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 we will be successful in recovering any amounts or the timing of such recovery pursuant to this litigation.

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 2008.

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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 traded on the New York Stock Exchange under the symbol “AVR.” As of February 29, 2008, there were 42,970,988 shares of Common Stock outstanding, held by 24 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.

	2008		2007
Period	High	Low	High	Low
First Quarter	$13.08	$4.71	$23.56	$14.78
Second Quarter	$6.05	$3.75	$20.68	$13.97
Third Quarter	$7.42	$3.10	$18.34	$10.14
Fourth Quarter	$3.42	$0.34	$13.27	$7.81

Dividends

We did not declare or pay cash dividends on our Common Stock during the years ended December 31, 2008, 2007 or 2006. We do not currently plan to pay cash dividends on our Common Stock. Any future determination to pay cash dividends will depend on our results of operations, financial condition, contractual restrictions and other factors deemed relevant by the Board of Directors. In addition, the agreement governing our secured revolving credit facility and our 10% fixed-rate unsecured notes generally restrict the payment of cash dividends on our Common Stock.

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Performance Graph

Set forth below is a line graph comparing the total stockholder return on our Common Stock since our shares began trading on the NYSE on June 29, 2006, with the cumulative total stockholder returns of both the S&P 500 index and the Custom Composite Index made up of two other public ethanol companies.

COMPOSITE PRICE CHART

TOTAL CUMULATIVE RETURNS

	2007				2008
	Mar	Jun	Sept	Dec	Mar	Jun	Sept	Dec
Aventine Renewable Energy Holdings, Inc	$47	$44	$28	$33	$14	$11	$8	$2
S&P 500	$113	$120	$123	$119	$107	$105	$96	$75
Peer Group	$77	$57	$43	$52	$26	$14	$10	$1

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Equity Compensation Plan Information

The following table provides information about our equity compensation plan as of December 31, 2008:

Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted average exercise price of outstanding options, warrants and rights	(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders (1)	4,017,499	$7.62 (2)	1,403,299
Equity compensation plans not approved by security holders	-0-		-0-
Total	4,017,499		1,403,299

(1)	Aventine Renewable Energy Holdings Inc. 2003 Stock Incentive Plan, as amended through April 30, 2008. The amount shown in column (a) consists of 3,893,882 stock options, 59,113 shares of unvested restricted stock and 64,504 restricted stock units.

(2)	Does not include outstanding rights to receive common stock upon the vesting of restricted stock units.

(3)	On April 30, 2008, the Compensation Committee agreed to amend the Stock Option Award Agreement for approved retirees by extending the option exercise term for up to two years or the date of the expiration of the options, whichever comes first, from the prior 90 day limit.

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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, 2008 and 2007 and the statement of operations data presented below for each of the years in the three-year period ended December 31, 2008, 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.

Statement of Operations Data:	Year Ended December 31,
	2008			2007			2006			2005			2004
(in thousands, except per share amounts)
Net sales	$	2,248,301		$	1,571,607		$	1,592,420		$	935,468		$	858,876
Cost of goods sold		2,239,340			1,497,807			1,460,806			848,053			793,070
Gross profit		8,961			73,800			131,614			87,415			65,806

Selling, general and administrative expenses		35,410			36,367			28,328			22,500			16,236
Demobilization costs associated with expansion projects		9,874			-			-			-			-
Impairment of plant development costs		1,557			-			-			-			-
Other income		(2,936	)		(1,113	)		(3,389	)		(989	)		(3,196	)
Operating income (loss)		(34,944	)		38,546			106,675			65,904			52,766

Other income (expense):
Loss on the sale of auction rate securities		(31,601	)		-			-			-			-
Interest expense		(5,077	)		(16,240	)		(9,348	)		(16,510	)		(2,035	)
Interest income		3,040			12,432			4,771			2,218			19

Loss on marketing alliance investment		(4,326	)		-			-			-			-
Loss on early extinguishment of debt		-			-			(14,598	)		-			-
Gain (loss) on derivative contracts		17,110			(78	)		3,654			1,781			(924	)
Minority interest		1,230			(1,338	)		(4,568	)		(2,404	)		(2,148	)
Income (loss) before income taxes		(54,568	)		33,322			86,586			50,989			47,678
Income tax expense (benefit)		(7,472	)		(477	)		31,685			18,807			18,433
Net income (loss)	$	(47,096	)	$	33,799		$	54,901		$	32,182		$	29,245

	Year Ended December 31,
	2008			2007		2006		2005			2004

Income (loss) per common share-basic	$	(1.12	)	$	0.81	$	1.43	$	0.93		$	0.84
Basic weighted-average common shares		42,136			41,886		38,411		34,686			34,684

Income (loss) per common share-diluted	$	(1.12	)	$	0.80	$	1.39	$	0.89		$	0.82
Diluted weighted-average common and common equivalent shares		42,136			42,351		39,639		36,052			35,768

Other Data (unaudited):
(In thousands, except per bushel and per gallon amounts)
Gallons sold		935,986			690,171		695,784		529,836			505,251
Capital expenditures	$	265,878		$	235,211	$	76,499	$	20,675		$	4,653
Average price per gallon of ethanol sold	$	2.22		$	2.08	$	2.18	$	1.63		$	1.55
Average price of corn per bushel	$	5.02		$	3.76	$	2.41	$	2.08		$	2.68

Balance Sheet Data:
(in thousands, at period end)
Total assets	$	799,459		$	762,185	$	408,136	$	221,977		$	163,598
Total debt (1)	$	352,200		$	300,000		-	$	161,514		$	172,791
Stockholders’ equity (deficit)	$	308,796		$	343,871	$	304,163	$	(20,654	)	$	(56,581	)

(1)	Total debt includes amounts outstanding under our revolving credit agreement, if any, and in 2008 and 2007, our 10% fixed-rate unsecured notes; in 2005 and 2004, our previous outstanding senior, secured floating rate notes.

(2)

EBITDA is defined as earnings before interest expense, interest income, income tax expense, depreciation, non-cash or non-recurring loss items. 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

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liquidity. 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 payments to us which are reflected in other income.

The following table reconciles our EBITDA to net income for each period presented:

	(Unaudited) For the Years Ended December 31,
(In thousands)	2008			2007			2006			2005			2004

Net income (loss)	$	(47,096	)	$	33,799		$	54,901		$	32,182		$	29,245
Depreciation		14,522			12,578			3,714			2,274			1,587
Interest expense		5,077			16,240			9,348			16,510			2,035
Loss on early extinguishment of debt		-			-			14,598			-			-
Loss related to auction rate securities		31,601			-			-			-			-
Impairment of plant development costs		1,557			-			-			-			-
Interest income		(3,040	)		(12,432	)		(4,771	)		(2,218	)		(19	)
Income tax expense/(benefit)		(7,472	)		(477	)		31,685			18,807			18,433
Earnings before interest, taxes, depreciation and amortization	$	(4,851	)	$	49,708		$	109,475		$	67,555		$	51,281

We have included EBITDA primarily as a performance measure because management uses it as a key measure of our performance and ability to generate cash necessary to meet our future requirements for debt service, capital expenditures, working capital and taxes.

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

The following discussion of our consolidated operating results and financial condition for the three years ended December 31, 2008 should be read in conjunction with the Consolidated Financial Statements, and related notes beginning on page F-1.

Overview

Our financial statements have been prepared on the going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. As a result of ethanol industry conditions that have negatively affected our business, we do not currently have sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. In particular, we do not expect to have adequate liquidity to satisfy the $15 million interest payment due on April 1, 2009 on our outstanding senior unsecured 10% fixed-rate notes or the $24.4 million due to our EPC contractor, Kiewit Energy Company (“Kiewit”). In addition, we are currently in default under our outstanding 10% fixed-rate notes which permits the holders thereof to accelerate the $300 million principal amount thereof upon 60 days notice. The default under our 10% fixed rate notes constitutes an event of default under our secured revolving credit facility, which has been waived by lenders under our secured revolving credit facility until April 15, 2009. As a result, our 2008 financial statements include an explanatory paragraph by our independent registered public accounting firm describing the substantial doubt as to our ability to continue as a going concern.

On March 10, 2009, we amended our secured revolving credit facility. See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Secured Revolving Credit Facility’’ for a more detailed description of our amended secured revolving credit facility.

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sources of liquidity. Based on the current spread between corn and ethanol prices, the industry is operating at or near breakeven cash margins. We experienced negative gross margins during the second half of 2008 and expect negative gross margins to continue through the first quarter of 2009 due in part to our fixed price obligations to purchase corn and natural gas at above current market prices. The current spread between ethanol and corn prices cannot support the long-term viability of the U.S. ethanol industry in general or us in particular.

In addition, although we suspended construction at both Aurora West and Mt. Vernon during the fourth quarter, 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 $24.4 million at February 28, 2009 are due and payable. 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 existing liquidity constraints.

We remain contractually obligated to complete the suspended plants at Aurora and Mt. Vernon as well as an additional plant at Mt. Vernon capable of producing 110 million gallons of ethanol annually and may incur significant penalties because of our failure to complete these facilities as previously scheduled.

We are a producer and marketer of fuel-grade ethanol in the U.S. Our own production facilities produced 188.8 million gallons of ethanol in 2008 and 192.0 million gallons of ethanol in 2007. 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 2008 and 2007, we distributed 754.3 million gallons and 506.5 million gallons, respectively, of ethanol produced by others. Taken together, we marketed and distributed 936.0 million gallons of ethanol in 2008 and 690.2 million gallons of ethanol in 2007. For the years ended December 31, 2008 and 2007, this represents approximately 11% and 10%, respectively, of the total volume of ethanol sold in the U.S. Because of the challenges facing the ethanol industry in general and us in particular, we expect to sharply decrease the number of gallons of ethanol we sell that are produced by others in 2009. We market and distribute ethanol to many of the leading energy companies in the U.S., including Royal Dutch Shell and its affiliates, Marathon Petroleum, BP, ConocoPhillips, Valero Marketing and Supply Company, Exxon/Mobil and Chevron. In addition to producing ethanol, our facilities also produce several co-products, such as distillers grain, corn gluten feed and meal, corn germ and brewers’ yeast, which generate incremental revenue and allow us to help offset a significant portion of our corn costs.

Because we market and sell ethanol without regard to the source, our general ledger system does not track or report ethanol revenue by source or the gallons of ethanol we sell by source. Our general ledger does track the number of gallons produced, the number of gallons purchased and the total number of gallons

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sold. We arrive at the change in inventory by subtracting the gallons produced and the gallons purchased from the total gallons sold. The difference is the amount of gallons taken from or put into inventory. We reconcile our calculated ethanol gallons in inventory to records kept by independent terminal operators on a monthly basis.

Our plants may operate at a capacity which is less than our stated capacity primarily because of scheduled and unscheduled outages and the amount of denaturant we blend into ethanol. For example, our plants ran at 94% of capacity for both 2008 and 2007 after adjusting for differences in denaturant blending levels.

Besides our own equity ethanol production, we also generate revenue by selling ethanol that we purchase from our marketing alliance partners. We expect ethanol sourced from marketing alliance partners to decline sharply going forward. See “Item 1 — Business — Marketing Alliances.”

We also resell ethanol that we purchase from unrelated producers and marketers which we also expect to decline sharply in 2009.

We generate additional revenue through the sale of by-products (both bio-products and co-products) that result from our ethanol production process. These by-products include brewers' yeast, corn gluten feed and meal, corn germ, condensed corn distillers solubles, 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 issues, may affect the volume of by-products produced. We may also shift the mix of these by-products, to optimize our revenue, by altering the production process. By-product revenue is driven by both the quantity of by-products produced and from the market price received for our by-products which have historically tracked the price of corn.

We increased our equity production capacity in early 2007 through the development of a 57 million gallon dry mill expansion of our Pekin, Illinois facility. We have also nearly completed construction of 113 million gallon annualized capacity ethanol production facilities at both Mt. Vernon, Indiana and Aurora, Nebraska. The construction of these facilities was suspended in the fourth quarter of 2008 due to our liquidity constraints and the economic issues facing the ethanol industry generally.

We continue to be obligated to build the plants at Aurora and Mt. Vernon where we have suspended construction as well as a second 110 million gallons of capacity at Mt. Vernon, Indiana through a phase II expansion and may incur significant penalties because of our failure to complete these facilities as previously scheduled. In addition, our long-term strategic plan originally envisioned us adding an additional 113 million gallons of capacity through a phase II expansion at Aurora, Nebraska, along with potentially expanding our existing Pekin, Illinois campus. In light of current market conditions and our liquidity position, we do not intend to pursue any of these expansions in the near term. Any future decisions regarding expansions will be based upon, among other factors, market conditions and the availability of financing on attractive terms.

Executive Summary

We generated net loss of $47.1 million, or $1.12 per diluted share in 2008, as compared to net income of $33.8 million, or $0.80 per diluted share, in 2007. Net income decreased primarily as a result of significantly higher corn costs, higher conversion costs, losses incurred on the sale of auction rate securities, valuation allowances established or increased for deferred tax assets, charges incurred from suspending construction at our expansion sites, the impairment of plant development costs and a loss recognized on one of our marketing alliance investments. Revenue in 2008 increased to $2.2 billion as compared to $1.6 billion in 2007.

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Gallons of ethanol sold in 2008 increased to 936.0 million from 690.2 million in 2007. Ethanol production for 2008 totaled 188.8 million gallons, a slight decrease from 192.0 million gallons in 2007. The decrease in production gallons was primarily due to blending at 1.96% denaturant for the entire year as opposed to 2007 where we blended at the higher rate for the first seven months. In 2008, the volume of ethanol purchased from marketing alliance partners increased due to marketing alliance partners coming on-line with new or expanded production facilities. Ethanol purchased from other producers and marketers was higher in 2008 versus 2007. We expect ethanol shipments in 2009 to decline sharply as we rationalize our supply sourcing in light of the current ethanol economic environment and as a result of our liquidity constraints.

Gross profit for 2008 fell to $9.0 million, a decrease of $64.8 million from 2007. The decline in gross profit was principally the result of higher corn prices, higher conversion costs and higher freight costs. This decline was partially offset by increased ethanol pricing, increased volumes of ethanol sold and increased co-product revenue. The average sales price per gallon of ethanol in 2008 was $2.22 per gallon, up from $2.08 per gallon in 2007. Positive gross margins in the first half of 2008 were partially offset by negative gross margins in the second half of 2008. We experienced negative gross margin of $41.5 million in the fourth quarter of 2008.

In 2008, the Company incurred losses totaling $31.6 million related to the sale of its portfolio of auction rate securities. The Company holds no auction rate securities as of December 31, 2008. As a result of the Company’s decision to suspend construction at Aurora, Nebraska and Mount Vernon, Indiana, we incurred demobilization charges totaling $9.9 million.

Income in 2008 also benefited significantly from $17.1 million in gains from derivative transactions.

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 complimentary 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.

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Conversion Costs

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

Summary of Critical Accounting Policies

We base this discussion and analysis of results of operations, cash flow and financial condition on our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the U.S.

Share-based Compensation Expense

Effective January 1, 2006, we adopted, on a modified prospective transition method, Statement of Financial Accounting Standards No. 123(R), Share-Based Payment (“SFAS 123(R)”), 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, 2008, 2007 and 2006 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 Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), 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 SFAS 123(R). In conjunction with the adoption of SFAS 123(R), we elected to attribute the value of share-based compensation to expense over the periods of requisite service using the straight–line method.

Upon adoption of SFAS 123(R), 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 SFAS 123. 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 2008 were estimated using a 3% forfeiture rate. During 2008, we adjusted the forfeiture rate to 6.4% 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.

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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 Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and by Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (hereinafter collectively referred to as “SFAS 133”), 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.

SFAS 133 requires a company to evaluate contracts to determine whether the contracts are derivatives. Certain contracts that meet the literal definition of a derivative under SFAS 133 may be exempted from the accounting and reporting requirements of SFAS 133 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 SFAS 133. Accordingly, these contracts are not recorded in our financial results until performance under them occurs.

Income Taxes

Under Statement of Financial Accounting Standards No. 109 (“SFAS 109”), Accounting for Income Taxes, deferred tax liabilities and assets are recorded for the expected future tax consequences of events that have been recognized in our financial statements or tax returns. Property, plant and equipment, stock-based compensation expense 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 $0.3 million for the year ended December 31, 2008 and $0.5 million for the years ended December 31, 2007 and 2006. Total estimated pension and postretirement expense in 2009 is expected to be similar to previous years. These expenses are primarily included in cost of goods sold, and in selling, general and administrative expenses. We made contributions to our defined benefit pension plan in 2008, 2007 and 2006 of $0.9 million, $0.5 million, and $2.0 million, respectively. In 2009, we expect to make contributions totaling $1.0 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.

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

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

Recent Accounting Pronouncements

In June 2008, the FASB issued FASB Staff Position (FSP) EITF Issue No. 03-6-1 (“FSP EITF 03-6-1”), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. FSP EITF 03-6-1 requires unvested share-based payment awards that contain rights to receive non-forfeitable dividends or dividend equivalents to be included in the two-class method of computing earnings per share as described in SFAS No. 128, Earnings per Share. This FSP was effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. Accordingly, we will adopt FSP EITF 03-6-1 in fiscal year 2009. We are currently evaluating the impact of FSP EITF 03-6-1 on the consolidated financial statements.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161 (“SFAS 161”), Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133. SFAS 161 requires entities to provide greater transparency in derivative disclosures by requiring qualitative disclosure about objectives and strategies for using derivatives and quantitative disclosures about fair value amounts of and gains and losses on derivative instruments. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15,

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2008. Accordingly, the Company adopted SFAS 161 as of January 1, 2009, noting it will have no material impact on the Company’s financial statements.

Results of Operations

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. Ethanol gallons sourced were as follows:

	For the Year Ended December 31,
(In thousands, except for percentages)	2008			2007			Increase/ (Decrease)			% Increase/ (Decrease)
Equity production		188,764			191,999			(3,235	)		(1.7)%
Marketing alliance purchases		505,254			395,001			110,253			27.9%
Purchase/resale		249,028			111,451			137,577			123.4%
Decrease (increase) in inventory		(7,060	)		(8,280	)		1,220		N.M.*
Total		935,986			690,171			245,815			35.6%
* Not meaningful

Net sales for 2008 were significantly higher as compared to 2007, at $2.2 billion for 2008 versus $1.6 billion in 2007. Overall, an increase in gallons sold and a higher average sales price of ethanol was complemented by higher co-product revenue. Gallons sold in 2008 increased reflecting a higher number of gallons marketed on behalf of marketing alliance partners and a higher number of gallons purchased from other producers, offset somewhat by lower equity production. In 2008, the volume of ethanol purchased from marketing alliance partners increased due to the addition of new or expanded alliance facilities, primarily in the second half of the year. We expect our net sales generated by the sale of ethanol produced by others to decline sharply in 2009 as we rationalize our supply sourcing in light of the current ethanol economic environment and our liquidity constraints. 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 compared to 2007 as the co-product prices failed to keep pace with the increase in corn prices in 2008.

Cost of goods sold for 2008 was $2.2 billion, a significant increase over the $1.5 billion in 2007. Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from our marketing alliance partners, the cost of purchasing ethanol and bio-diesel from other producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers. We expect the absolute dollar amount of cost of goods sold to decline sharply in 2009 as we terminate our marketing alliances.

Purchased ethanol in 2008 totaled $1.5 billion, versus approximately $972.5 million in 2007. The increase in purchased ethanol results 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. We expect the absolute dollar amount of purchased ethanol to decline sharply in 2009 as we reduce our purchases of ethanol.

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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 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 is 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 is 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 Southeast.

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 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 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 is principally due to a reduction in available funds to invest.

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

The minority interest for 2008 was a $1.2 million credit to income compared to $1.3 million charge to income for 2007. This increase reflects the reduced operating performance of our Nebraska subsidiary caused primarily by the year over year significant increase in corn. 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 includes $17.1 million net realized and unrealized gains on derivative contracts. This includes the effect of marking to market these contracts at December 31, 2008.

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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 net losses on short gasoline forward contracts totaling $8.7 million.

The Company’s annual tax benefit rate for 2008 was 13.7% of pre-tax loss. The income tax benefit recorded in 2008 is 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 believe is more likely than not to be realized. The valuation allowance includes $12.3 million of reserve against the income tax benefit related to the losses incurred on auction rate securities as we do not expect to have sufficient capital gains to offset the $31.6 million capital loss.

Year Ended December 31, 2007, Compared with Year Ended December 31, 2006

Total gallons shipped in 2007 were 690.2 million gallons, versus 695.8 million gallons shipped in 2006, a decrease of 5.6 million gallons or 0.8%. The increase/(decrease) in gallons by source was as follows:

	For the Year Ended December 31,
(In thousands, except for percentages)	2007			2006		Increase/ (Decrease)			% Increase/ (Decrease)
Equity production		191,999			132,957		59,042			44.4%
Marketing alliance purchases		395,001			492,973		(97,972	)		(19.9)%
Purchase/resale		111,451			68,234		43,217			63.3%
Decrease (increase) in inventory		(8,280	)		1,620		(9,900	)	N.M.*
Total		690,171			695,784		(5,613	)		(0.8)%
* N.M. – not meaningful

Net sales for 2007 were relatively flat as compared to 2006, at $1.6 billion for 2007 and 2006. Overall, a decrease in gallons sold and a decline in the average sales price of ethanol was offset by higher co-product revenue and the addition of revenue from the marketing of bio-diesel. Gallons sold in 2007 decreased reflecting a lower number of gallons marketed on behalf of marketing alliance partners, offset somewhat by higher equity production from our new Pekin dry mill and a higher number of gallons purchased from other producers. In 2007, the volume of ethanol purchased from marketing alliance partners decreased due to the loss at the end of the first quarter of a major alliance partner. This was offset somewhat by additions to our marketing alliance throughout the year. By year end 2007, we had essentially replaced all of the gallons caused by the loss of the alliance partner in the first quarter of 2007. The average gross selling price of ethanol in 2007 decreased to $2.08 per gallon, from the $2.18 received in 2006.

Co-product revenue for 2007 totaled $99.3 million, an increase of $44.6 million or 81.5%, from the 2006 total of $54.7 million. Co-product revenue increased during 2007 versus 2006 principally from an increase in co-product tonnage sold as a result of the DDGS produced from the new dry mill, along with higher average selling prices. In 2007, we sold 1.1 million tons, versus 0.9 million tons in 2006. Co-product revenues, as a percentage of corn costs, were 36.7% during 2007, versus 44.7% in 2006. Co-product returns, as a percentage of corn costs, decreased in 2007 as compared to 2006 as the result of increases in the price of corn outpacing the increase in co-product pricing, and from the mix of co-products produced. Due to the addition of the new dry mill in Pekin, the increase in lower value DDGS production reduced the percentage of the lower value DDGS to the overall mix of available co-products.

Cost of goods sold for 2007 versus 2006 was also relatively flat at $1.5 billion. Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from our marketing alliance partners, the cost of purchasing ethanol and bio-diesel from other producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers.

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Purchased ethanol in 2007 totaled $972.5 million, versus approximately $1.1 billion in 2006. The decrease in purchased ethanol resulted from a decrease in the number of gallons of ethanol purchased from marketing alliance partners, along with a decrease in the cost per gallon of ethanol purchased. In 2007, we purchased 506.5 million gallons of ethanol at an average cost of $1.92 per gallon as compared to 561.2 million gallons of ethanol at an average cost of $2.06 in 2006. In 2007, the volume of ethanol purchased from marketing alliance partners decreased due to the loss at the end of the first quarter of a major alliance partner. This was offset somewhat by additions to our marketing alliance throughout the year. By year end 2007, we had essentially replaced all of the gallons caused by the loss of the alliance partner in the first quarter of 2007. Net declines in marketing alliance volume were partially offset by increased purchases from third party producers.

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 2007 totaled $270.4 million or $3.76 per bushel, versus $122.4 million, or $2.41 per bushel in 2006. The increase in corn costs was due to a combination of increased bushels of corn consumed by the new Pekin dry mill which came on-line in January 2007, along with significantly increased prices due to increased demand in the marketplace as a result of expected new ethanol production facilities being built and increased demand for grains on a global basis. We believe that speculation in corn commodity futures markets may have further exacerbated the issue of rising corn costs.

Conversion costs for 2007 increased to $117.0 million from $87.2 million for 2006. The total dollars spent on conversion costs increased year over year principally as a result of the new Pekin dry mill production. However, the conversion cost per gallon declined year over year to $0.61 per gallon in 2007 versus $0.66 per gallon in 2006. Our plants ran at 94% of capacity for 2007 and 89% for 2006 after adjusting for differences in denaturant blending levels.

Depreciation for 2007 totaled $12.6 million, versus $3.7 million in 2006. The increase in depreciation expense was the result of the new Pekin dry mill beginning production. Motor fuel taxes were $13.9 million in 2007 versus $13.6 million in 2006. The cost of motor fuel taxes are recovered through billings to customers.

Freight/logistics costs in 2007 increased to $120.2 million, or approximately $0.17 per gallon, from $101.7 million, or $0.15 per gallon in 2006. 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 from the expansion of our distribution system footprint, along with higher general freight and barge expenses. Fuel surcharges impacted general freight rates in 2007.

The average cost of inventory was $1.80 at the end of 2007 as compared to $1.91 at the end of the 2006 reflecting the decline in the average ethanol prices in 2007 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 2006 during 2007 (a period of lower average selling prices) was an increase in cost of goods sold of approximately $4.0 million.

SG&A expenses were $36.4 million in 2007, compared to $28.3 million in 2006. Year over year increases reflected increased expenditures for legal and other professional fees associated with our being a public company including the costs of complying with Section 404 of Sarbanes-Oxley Act of 2002 and increased IT costs. Increased legal fees related to our capacity expansion efforts also increased SG&A expenses.

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Interest income in 2007 was $12.4 million, versus $4.8 million in 2006. The increase in interest income was due to a combination of a higher average level of funds available to invest as a result of our March 2007 note offering and higher short-term investment rates due to increases in interest rates in general.

Interest expense in 2007 was $16.2 million, as compared to $9.3 million in 2006. Interest expense in 2007 reflected interest incurred from March 2007 through December 2007 on our $300 million aggregate principal amount of senior unsecured 10% fixed-rate notes. In 2006, we had outstanding $160 million aggregate principal amount of floating rate senior secured notes, the majority of which was repurchased in July 2006.

The minority interest for 2007 was a $1.3 million charge to income compared to $4.6 million charge to income for 2006. This decrease reflected the reduced operating performance of our Nebraska subsidiary caused primarily by the year over year significant increase in corn costs along with a lower average price received per gallon in 2007 as compared to 2006 from the sale of ethanol.

Other non-operating income for 2007 included a net $0.1 million realized and unrealized loss on derivative contracts. This included the effect of marking to market these contracts at December 31, 2007. Net gains on corn derivatives totaling $8.6 million were offset by net losses on short gasoline forward contracts totaling $8.7 million. For 2006, we recognized $3.7 million of net realized and unrealized gains on corn derivative contracts.

An audit of our federal income tax returns covering fiscal years 2004 and 2005 by the IRS was completed in September 2007. As a result, the Company was able to finalize positions relating to certain tax matters which required liability recognition under FIN 48. The Company recognized in 2007 a previously unrecorded favorable tax benefit of $9.6 million, which included its previously recorded liability for uncertain tax benefits, the related interest and the release of code Section 382 valuation allowances.

The Company’s annual tax rate for 2007, exclusive of the adjustment discussed above, was 28.2%. The difference between the Company’s effective annual tax rate and the statutory rate was primarily the result of significant amounts of tax-exempt interest income.

Trends and Factors that May Affect Future Operating Results

Need for Additional Liquidity

We do not have sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. We are actively pursuing a number of liquidity alternatives, including seeking additional debt and equity financing and a potential sale of all or part of the company. There can be no assurance we will be successful. If we cannot obtain sufficient liquidity in the very near-term, we may need to seek to restructure under Chapter 11 of the U.S. Bankruptcy Code.

Supply and Demand

Ethanol demand in 2008 exceeded U.S. ethanol production by 500 million gallons. In 2008, U.S. production capacity increased by 42.3% while demand increased by only 40.7%. Despite the demand growth in 2008, increased penetration in new markets, and a government mandate, the production capacity of U.S. ethanol producers is expected to continue to exceed demand. Factors that could influence the balance of U.S. ethanol supply and demand over the near-term include discretionary blending economics, oversupply, and the carryover of excess renewable identification numbers.

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At the end of 2008, there was approximately 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 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 resilent hybrid varieties of corn.

We have purchased forward approximately 5.2 million bushels (or approximately 28%) of our corn requirements for the first quarter of 2009 at an average price of $5.53 per bushel which is currently significantly above the CBOT spot price for corn. This may cause operating margins through the first quarter of 2009 to be negative or below that of our competitors.

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 2008. Our current natural gas usage is approximately 262,000 MMBtus per month. Through the first quarter of 2009, our operating margins may be below our competitors because we have fixed price obligations to purchase natural gas at above current market prices.

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 11.1 billion gallons in 2009 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 West and Mt. Vernon as well as the “phase II” ethanol plant at Mt. Vernon capable of producing 110 million gallons ethanol annually 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.”

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Cancellation of indebtedness income

Section 382 limitations

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Liquidity and Capital Resources

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

	December 31, 2008	December 31, 2007
(In thousands)
Cash and cash equivalents	$23,339	$17,171
Short-term investments	$ -	$211,500
Net working capital	$(294,039)	$303,377
Total debt	$352,200	$300,000
Current ratio	0.39	3.90

Overview and Outlook

As a result of ethanol industry conditions that have negatively affected our business, we do not currently have sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. In particular, we do not expect to have adequate liquidity to satisfy the $15 million interest payment due on April 1, 2009 on our outstanding senior unsecured 10% fixed-rate notes or the $24.4 million due to our EPC contractor, Kiewit. In addition, we are currently in default under our outstanding 10% fixed-rate notes which permits the holders thereof to accelerate the $300 million principal amount thereof upon 60 days notice. The default under our 10% fixed rate notes constitutes an event of default under our secured revolving credit facility, which has been waived by lenders under our secured revolving credit facility until April 15, 2009. As a result, our 2008 financial statements include an explanatory paragraph by our independent registered public accounting firm describing the substantial doubt as to our ability to continue as a going concern. Because of the default under our 10% fixed rate notes, we have classified the entire $300 million principal amount as a current liability in our balance sheet at December 31, 2008.

The amount of cash and borrowings available to us under our secured revolving credit facility at the end of the fourth quarter of 2008 declined to $23.3 million, from $119.2 million at the end of the third quarter of 2008. On March 10, 2009, we amended our secured revolving credit facility. See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Secured Revolving Credit Facility’’ for a more detailed description of our amended secured revolving credit facility.

The material terms of the amended facility include:

·	An initial reduction in the revolving commitment on a graduated scale from $200 million to $75 million, and reducing to $60 million on April 1, 2009 and $50 million on May 1, 2009 and thereafter (subject to collateral availability);

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·	Certain adjustments to the borrowing base calculation, including a decrease in the fixed asset component from $50 million amortized at $1.8 million per quarter under the prior facility to $10 million, with amortization of $1 million per month beginning on September 1, 2009;

·	A reduction in the availability block from $50 million to $2.5 million;

·	A provision that permits the filing by our creditors of certain precautionary liens provided they do not commence enforcement action;

·	An increase in interest rates and commitment fees;

·	A shortening of the maturity date to March 1, 2010;

·	The deletion of a fixed charge coverage covenant;

·	A provision that permits our independent registered public accounting firm to express uncertainty regarding our ability to remain a “going concern” in respect of our 2008 financial statements;

·	Adjustments to certain reporting requirements; and

A requirement that the Company notify the Administrative Agent no later than March 31, 2009 that a formal written agreement or irrevocable tender is in place to complete an exchange offer between the Company and the holders of at least 80% in principal amount of its senior unsecured 10% fixed-rate notes. The exchange offer must be completed with the holders of at least 90% in principal amount of its senior unsecured 10% fixed-rate notes by April 15, 2009.

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In addition, although we suspended construction at both Aurora West and Mt. Vernon during the fourth quarter, 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 $24.4 million at February 28, 2009 are due and payable. 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 existing liquidity constraints.

We remain contractually obligated to complete the suspended plants at Aurora and Mt. Vernon as well as an additional plant at Mt. Vernon capable of producing 110 million gallons of ethanol annually 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, short-term investments, cash provided by operations, and cash available under our secured revolving credit facility.

Cash and short-term investments. During 2008, cash and short-term investments decreased by $205.3 million. Cash and short-term investments as of December 31, 2008 and 2007 were $23.3 million and $228.7 million, respectively. The decrease in cash and short-term investments is principally the result of liquidation of our short-term investments at a loss of $31.6 million and capital expenditures related to our plant expansions offset somewhat by cash provided by operations.

Cash provided by operations. Net cash provided by operating activities in 2008 was $35.6 million, as compared to $47.6 million for 2007. The decrease in net cash provided by operating activities is primarily the result of operating losses sustained primarily during the fourth quarter.

Cash available under our credit facility. We amended our secured revolving credit facility in March 2009. The new facility provides for a reduction in the revolving commitment on a graduated scale from $200 million to initially $75 million, and reducing to $60 million on April 1, 2009 and $50 million on May 1, 2009 and thereafter (subject to collateral availability). See “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation - Secured Revolving Credit Facility” below for more information about our secured revolving credit facility.

As of March 12, 2009, $22.2 million in letters of credit and $16.5 million in revolving loans were outstanding under the secured revolving credit facility. After giving effect to the recent amendment to our

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secured revolving credit facility, we had $0.7 million of cash and $6.6 million of additional borrowing availability thereunder as of such date. All of our cash receipts are automatically applied to reduce amounts outstanding under our amended secured revolving credit facility and to cash collateralize our letters of credit. As we continue to reduce the number of gallons of ethanol we sell and hold in inventory, working capital available to support borrowings under our secured revolving credit facility will reduce proportionately.

Uses of Liquidity

Our principal uses of liquidity have been capital expenditures, funding of operating losses, losses incurred in the liquidation of our ARS investments and interest payments.

Capital expenditures. Capital expenditures for the expansion of our now suspended expansion facilities totaled $225.1 million in 2008 and $211.7 million in 2007, excluding $26.4 million and $7.3 million of capitalized interest, respectively. Capital expenditures for 2008 exclude amounts owed to Kiewit of $17.5 million at December 31, 2008.

In 2008, other capital expenditures (excluding expenditures made for capacity expansions) totaled $9.9 million versus $16.2 million in 2007. Other capital expenditures include asset replacement, environmental and safety compliance, and cost reduction and productivity improvement items. Our capital spending plan for 2009, excluding any expenditures for facility additions or expansion, is forecasted to be between $5 million and $10 million.

Payments related to our outstanding debt and credit facility. In 2008, we made interest payments on our $300 million senior unsecured 10% fixed-rate notes totaling $30.0 million and $1.5 million interest payments for borrowings on our credit facility. In 2007, we made interest payments on our $300 million senior unsecured 10% fixed -rate notes totaling $15.3 million. The increase in interest payments from 2007 to 2008 results primarily from our senior unsecured 10% fixed-rate notes being outstanding for the entire year along with amounts borrowed in 2008 on our secured revolving credit facility.

Repurchase of shares of common stock. In 2008, we did not repurchase any shares of our common stock. In 2007, we repurchased 319,615 shares of our common stock at an average price of $9.33, spending a total of approximately $3.0 million. These shares were repurchased under a share repurchase program approved by our Board of Directors. The share repurchase program allows the repurchase of up to $50 million of our outstanding common stock, although there are no minimum share purchase requirements. There is approximately $45.9 million available to be repurchased under this program.

Off-Balance Sheet Arrangements

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

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Contractual Obligations and Commercial Commitments

The following table provides a summary of our contractual obligations and commercial commitments as of December 31, 2008. 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 14 and 15 of the Notes to the Consolidated Financial Statements.

	Payments due or expiring by period
(In thousands)	Total	Less Than 1 year	1-3 years	3-5 years	More than 5 years
Contractual obligations:
Purchased Ethanol (1)	13,306.6	1,330.7	2,661.3	2,661.3	6,653.3
Senior Unsecured 10% Fixed Rate Notes (2)	300.0	-	-	-	300.0
Secured Revolving Credit Facility (3)	52.2	-	52.2	-	-
Bond Interest (2)	255.0	30.0	60.0	60.0	105.0
Railcars (4)	131.9	18.8	35.5	31.1	46.5
Corn	35.2	35.2	-	-	-
Commitments for Capital Expenditures	47.7	47.7	-	-	-
Derivatives	26.7	26.7	-	-	-
Terminals (4)	28.6	10.7	9.8	4.5	3.6
Coal Contracts	18.0	18.0	-	-	-
Mt. Vernon Lease	6.5	0.4	0.7	0.7	4.7
Ports of Indiana Wharfage	4.6	0.1	0.5	0.5	3.5
Natural Gas	4.8	4.8	-	-	-
Purchased Biodiesel	6.2	6.2	-	-	-
Barges (4)	3.9	3.1	0.8	-	-
Other	9.0	3.3	4.0	1.2	0.5
Total Contractual obligations	$14,236.9	$1,535.7	$2,824.8	$2,759.3	$7,117.1

(1)

The dollar value of our commitments under these contracts is estimated based on the volume commitment under the contracts, purchased ethanol contracts not being renewed upon termination and an estimated ethanol purchase price of $1.44. Under these contracts, we are generally obligated to purchase a set volume of ethanol at a purchase price that is based upon an average price at which we sell ethanol less a pre-negotiated margin. As a result, our exposure to market risk under these contracts as a result of fluctuations in ethanol prices is limited. The estimated ethanol price used in this disclosure should not be relied upon as a forecast of ethanol prices in future periods.

(2)

These commitments assume cash payment of principal and interest as scheduled on our 10% fixed rate notes. We are currently in default on such notes, which permits our bondholders to accelerate the debt with 60 days notice. Additionally, we have an obligation to execute an exchange of these bonds prior to April 15, 2009.

(3)

This commitment assumes cash payment of the December 31, 2008 outstanding balance when the facility expires in March 2012. Subsequent to December 31, 2008, the facility was amended with an expiration date of March 1, 2010 and borrowings are limited to collateral available. Collateral availability under the amended facility is determined via a borrowing base, which includes a percentage of eligible receivables and inventory, and no more than $10 million of property, plant and equipment. Also under the amended facility, all working capital proceeds are automatically applied to reduce amounts outstanding and to cash collateralize our letters of credit.

(4)	Subsequent to year end, we entered into subleases or other assignments reducing the obligation by approximately $85.7 million in total, subject to performance by our sublessees.

Secured Revolving Credit Facility

We amended our existing secured revolving credit facility on March 10, 2009. Our amended liquidity facility consists of a secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent and a lender. The revolving commitment declines from $200 million to initially $75 million, and reducing to $60 million on April 1, 2009 and $50 million on May 1, 2009 and thereafter (subject to collateral availability). The amended liquidity facility includes a $25 million sub-limit for letters of credit. The credit facility expires on March 1, 2010, and is secured by substantially all of the Company’s assets. The default under our 10% fixed rate notes related to the Kiewit liens constitutes an event of default

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under our secured revolving credit facility. We have obtained a waiver of this event of default from the lenders under our secured revolving credit facility until April 15, 2009.

Collateral availability under the amended facility is determined via a borrowing base, which includes a percentage of eligible receivables and inventory, and no more than $10 million of property, plant and equipment. The amount of property, plant and equipment which can be included in the borrowing base reduces at a rate of $1.0 million each month beginning on September 1, 2009.

Borrowings on the amended facility generally bear interest, at our option, at the following rates (i) the Eurodollar or the LIBO rate plus a margin of 4.5%, with a LIBO rate minimum of 3%, or (ii) the greater of the prime rate or the federal funds rate plus 0.50% (with a minimum rate of LIBOR plus 2.25%), plus a margin of 3.25%. Accrued interest is payable monthly on outstanding principal amounts, provided that accrued interest on Eurodollar loans is payable at the end of each interest period, but in no event less frequently than quarterly. In addition, the following fees are also applicable: an unused commitment fee of 0.50% on unused borrowing availability, an outstanding letters of credit fee of 4.625%, and administrative and legal costs.

Availability under our amended secured revolving credit facility is subject to customary conditions, including the representations and warranties, the absence of any material adverse change and covenants, which, among other things, limit our ability to incur additional indebtedness and liens; enter into transactions with affiliates; make acquisitions; pay dividends; redeem or repurchase capital stock or senior notes; make investments or loans; make negative pledges; consolidate, merge or effect asset sales; or change the nature of our business.

The secured revolving credit facility contains customary events of default for credit facilities of this size and type, and includes, without limitation, payment defaults; defaults in performance of covenants or other agreements contained in the transaction documents; inaccuracies in representations and warranties; certain defaults, termination events or similar events; certain defaults with respect to any other Company indebtedness in excess of $5.0 million; certain bankruptcy or insolvency events; the rendering of certain judgments in excess of $5.0 million; certain ERISA events; certain change in control events and the defectiveness of any liens under the secured revolving credit facility. In addition, the amendment to our secured revolving credit facility requires us to successfully complete an exchange offer of our outstanding senior unsecured 10% fixed-rate notes for a like principal amount of a new series of “pay-in-kind” notes. Failure to have the holders of 80% of the existing senior unsecured 10% fixed-rate notes commit to participate in the exchange by March 31, 2009 or the failure to consummate the exchange for 90% of the existing senior unsecured 10% fixed-rate notes by April 15, 2009 would be an event of default under our secured revolving credit facility. Obligations under the secured revolving credit facility may be accelerated upon the occurrence of an event of default.

Environmental Matters

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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. 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.

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.

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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.

See Note 16 of Notes to Consolidated Financial Statements for more information on our environmental commitments and contingencies.

Market Risks

We are exposed to various market risks, including changes in commodity prices and interest rates. Market risk is the potential loss arising from adverse changes in market rates and prices. In the ordinary course of business, we enter into various types of transactions involving financial instruments to manage and reduce the impact of changes in commodity prices and interest rates.

Commodity Price Risks

We are subject to market risk with respect to the price and availability of corn, the principal raw material we use to produce ethanol and ethanol by-products. In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions. This is especially true when market conditions do not allow us to pass along increased corn costs to our customers. The availability and price of corn is subject to wide fluctuations due to unpredictable factors such as weather conditions, farmer planting decisions, governmental policies with respect to agriculture and international trade, and global demand and supply. Our weighted-average gross corn costs for the years ended December 31, 2008 and 2007 were $5.02 and $3.76 per bushel, respectively.

We have firm-price purchase commitments with some of our corn suppliers under which we agree to buy corn at a price set in advance of the actual delivery of that corn to us. Under these arrangements, we assume the risk of a decrease in the market price of corn between the time this price is fixed and the time the

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corn is delivered. At December 31, 2008, we had firm-price purchase commitments to purchase 6.3 million bushels of corn at an average fixed price of $5.61 per bushel for delivery through December 2009. We have elected to account for these transactions as normal purchases under SFAS 133, and accordingly, have not marked these transactions to market. In order to reduce our market exposure to price decreases, at the time we enter into a firm-price purchase commitment, we also often enter into commodity futures contracts to sell a like amount of corn at the then-current price for delivery to the counterparty at a later date. We account for these futures transactions under SFAS 133. These futures contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative contracts are recognized in other current assets in the Consolidated Balance Sheet, net of any cash paid to brokers. Information on this type of derivative transaction is as follows:

	Year Ended December 31,
(In millions)	2008	2007

Realized and unrealized net gain included in earnings	$10.5	$2.9

	December 31,
(In millions)	2008	2007

Net bushels sold	5.0	3.9
Aggregate notional value of derivatives outstanding	$26.7	$16.5
Period through which derivative positions currently exist	December 2009	December 2009
Unrealized gain on fair value of derivatives	$6.0	$1.5
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$(2.1)	$(1.8)

We have also entered into commodity futures contracts in connection with the purchase of corn to reduce our risk of future price increases. We account for these transactions under SFAS 133. These futures contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative contracts are recognized in other current assets in the Consolidated Balance Sheet, net of any cash received from the brokers. Information on this type of derivative transaction is as follows:

	Year Ended December 31,
(In millions)	2008	2007

Realized and unrealized net gain included in earnings	$7.9	$4.6

	December 31,
(In millions)	2008	2007

Net bushels bought	-	5.3
Aggregate notional value of derivatives outstanding	$-	$22.4
Period through which derivative positions currently exist	-	July 2008
Unrealized gain on fair value of derivatives	$-	$2.6
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$-	$(2.5)

We are also subject to market risk with respect to ethanol pricing. Our ethanol sales are priced using contracts that can either be based upon a fixed price; based upon the price of wholesale gasoline plus or minus a fixed amount; or based upon a market price at the time of shipment. We sometimes fix the price at which we sell ethanol using fixed price physical delivery contracts. At December 31, 2008, we had fixed contracts to sell approximately 4.2 million gallons of ethanol at an average fixed price of $2.41 per gallon

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through December 2009. We have elected to account for these transactions as normal sales under SFAS 133, and accordingly, have not marked these transactions to market.

We also sell forward ethanol using contracts where the price is determined at a point in the future based upon an index plus or minus a fixed amount. At December 31, 2008, we had sold forward approximately 4.9 million gallons of ethanol using wholesale gasoline as an index plus a fixed spread that averaged a negative $0.55 per gallon. Under these arrangements, we assume the risk of a price decrease in the market price of gasoline. In order to reduce our market exposure to price decreases, at the time we enter into a firm sales commitment, we may also enter into commodity forward contracts to sell a like amount of gasoline at the then-current price for delivery to the counterparty at a later date. We account for these transactions under SFAS 133. These forward contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative liabilities is recognized in other current liabilities in the Condensed Consolidated Balance Sheet, net of any cash paid to brokers. Information on this type of derivative transaction is as follows:

	Year Ended December 31,
(In millions)	2008	2007

Realized and unrealized net loss included in earnings	$1.3	$8.7

	December 31,
(In millions)	2008	2007

Gallons sold	-	24.1
Aggregate notional value of derivatives outstanding	$ -	$55.1
Period through which derivative positions currently exist	-	December 2008
Unrealized loss on fair value of derivatives	$ -	$(5.8)
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$ -	$(6.1)

We may also be subject to market risk with respect to our supply of natural gas which is consumed during the production of ethanol and its co-products and has historically been subject to volatile market conditions. Natural gas prices and availability are affected by weather conditions, overall economic conditions and foreign and domestic governmental regulation. The price fluctuation in natural gas prices over the nine year period from 1999 through December 2008, based on the New York Mercantile Exchange daily futures data, has ranged from a low of $1.63 per MMBtu in 1999 to a high of $15.82 per MMBtu in 2005. Natural gas costs comprised 24.2% and 18.7%, respectively, of our total conversion costs for the years ended December 31, 2008 and 2007.

At December 31 2008, we had purchased forward 459,350 MMBtu’s of natural gas at an average fixed price of $10.33 per MMBtu through the first quarter of 2009. We have elected to account for these transactions as normal purchases under SFAS 133, and accordingly, have not marked these transactions to market. Based upon our annual average estimated natural gas usage and the December 31, 2008 year end price of natural gas of $9.56 per MMBtu, a 10% increase in natural gas prices would negatively affect our results of operations by approximately $3.0 million.

Interest Rate Risk

The fair market value of long-term fixed interest rate debt is subject to interest rate risk. Generally, the fair market value of fixed interest rate debt will increase as interest rates fall and decrease as interest rates rise. The estimated fair value of our total long-term fixed interest rate debt as of December 31, 2008 was $49.5 million, versus a carrying value of $300.0 million. At December 31, 2007, the estimated fair value of our long-term fixed interest rate debt was $274.5 million versus a carrying value of $300 million.

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A 1% increase from prevailing interest rates would result in a decrease in fair value of this debt by approximately $0.8 million as of December 31, 2008. The estimated fair market value of our debt is based upon the indicative bid price for our Senior Notes which approximates their trade value. The yield implicit in the value of the 10.0% Senior Notes is 60.6% as of December 31, 2008. Generally, changes in the market value of our fixed-rate debt do not affect us, unless we repurchase the debt in the open market.

Material Limitations

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

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

Subsequent Events

On February 16, 2009, Ajay Sabherwal, our Chief Financial Officer, submitted his resignation, effective March 13, 2009, to the Company in order to pursue another opportunity. George Henning was appointed Interim Chief Financial Officer effective March 16, 2009.

On March 9, 2009, we 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 $24.4 million at February 28, 2009 are due and payable.

Because our obligations to Kiewit are past due, the liens securing these obligations violate the terms of our 10% fixed rate notes and constitute a default thereunder. Unless such default is cured through payment, the release of the liens, a negotiated resolution or otherwise, the holders of our 10% fixed rate notes may accelerate the $300 million principal amount thereof upon 60 days notice. In addition, the default under the 10% fixed rate notes constitutes an event of default under our secured revolving credit facility, which has been waived by the lenders thereunder until April 15, 2009.

On March 10, 2009, we amended our secured revolving credit facility.

Due to severely declining margins and general liquidity stress due to frozen credit markets, we are significantly reducing the number of gallons we source from third parties. Beginning in the fourth quarter of 2008, we began negotiating termination agreements with most of our marketing alliance partners and subsequent to year-end have negotiated termination of nearly all of them. We received termination settlements of $14.1 million. We have also undertaken a strategy to rationalize our distribution and logistics system to focus primarily on our equity production. This rationalization process is expected to entail significantly reducing or eliminating our presence in numerous terminals, the amount of ethanol transported via barge, and the number of railcars we use to distribute ethanol. In connection with the rationalization, we have subleased or assigned the majority of our railcar, barge and terminal leases. On sublease arrangements, we remain secondarily liable to the lessor.

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

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Impact of Recently Issued Accounting Standards

See Note 2, Summary of Critical Accounting Policies - Recent Accounting Pronouncements, of the Notes to Consolidated Financial Statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The information required by this item is contained in “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations” and is incorporated herein by reference.

Item 8. Financial Statements and Supplementary Data

	Page
Consolidated Statements of Operations — For the years ended December 31, 2008, 2007 and 2006.	F-1
Consolidated Balance Sheets — December 31, 2008 and 2007.	F-2
Consolidated Statements of Stockholders’ Equity (Deficit) — For the years ended December 31, 2008, 2007 and 2006.	F-3
Consolidated Statements of Cash Flows — For the years ended December 31, 2008, 2007 and 2006.	F-4
Notes to Consolidated Financial Statements.	F-5
Report of Independent Registered Public Accounting Firm.	F-38
Report of Independent Registered Public Accounting Firm.	F-39

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision of, and with the participation of management, including our Chief Executive Officer, Ronald H. Miller who is also currently serving as our Acting Chief Financial Officer, the Company carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report. Based upon that evaluation, Mr. Miller has concluded that, as of the end of the period covered by this report, the Company’s disclosure controls and procedures have been designed and are effective to provide reasonable assurance that information required to be disclosed in the reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. These disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed in such reports is accumulated and communicated to our management, including Mr. Miller, as appropriate to allow timely decisions regarding the required disclosure. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events. There can be no assurance that any design will succeed in achieving its stated goal under all potential future conditions, regardless of how remote.

Changes in Internal Control over Financial Reporting

Based upon the evaluation performed by our management, which was conducted with the participation of Mr. Miller, there has been no change in our internal control over financial reporting during the fourth quarter of 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a–15(f). Management, with the participation of Mr. Miller, assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, management used the framework set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon this assessment, our management concluded that, as of December 31, 2008, our internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved.

The effectiveness of internal control has been audited by Ernst & Young LLP, independent registered public accounting firm, as stated in their report on page F-34 included in this 10-K.

Inherent Limitation of the Effectiveness of Internal Control

A control system, no matter how well conceived and operated, can only provide reasonable, not absolute, assurance that the objectives of the internal control system are met. Because of the inherent limitations of any internal control system, no evaluation of controls can provide absolute assurance that all control issues, if any, within a company have been detected.

Item 9B. Other Information

None.

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PART III

Item 10. Directors and Executive Officers of the Registrant

The information required by this item with respect to our directors, audit committee, and our audit committee financial experts is incorporated by reference from the information under the caption “Election of Directors” contained in our definitive proxy statement for the 2009 Annual Meeting of Stockholders. The required information concerning our executive officers is incorporated by reference from the information under the caption “Executive Officers of the Registrant” contained in our definitive proxy statement for the 2009 Annual Meeting of Stockholders. The required information concerning our adoption of a code of ethics that applies to our chief executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions and the availability of this code of ethics upon written request is contained in “Part I – Item 1 – Business – Available Information” of this report.

The required information concerning compliance with Section 16(a) of the Exchange Act is incorporated by reference from the information under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” contained in our definitive proxy statement for the 2009 Annual Meeting of Stockholders.

Item 11. Executive Compensation

The information required by this item is incorporated by reference from the information under the captions “Executive Compensation” in our definitive proxy statement for the 2009 Annual Meeting of Stockholders.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item is incorporated by reference from the information under the caption “Stock Ownership of Certain Beneficial Owners and Management” and “Executive Compensation - Equity Compensation Plan Information” in our definitive proxy statement for the 2009 Annual Meeting of Stockholders.

Item 13. Certain Relationships and Related Transactions

The information required by this item is incorporated by reference from the information contained under the caption “Executive Compensation - Certain Relationships and Related Transactions” in our definitive proxy statement for the 2009 Annual Meeting of Stockholders.

Item 14. Principal Accounting Fees and Services

The information required by this item is incorporated by reference from the information under the caption “Ratification of Appointment of Independent Auditors - Principal Accounting Firm Fees” and “Ratification of Appointment of Independent Auditors – Audit Committee’s Pre-Approval Policies and Procedures” contained in our definitive proxy statement for the 2009 Annual Meeting of Stockholders.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)	Index to exhibits, financial statements and schedules.

(1)

The following consolidated financial statements and reports are included beginning on page F-1 hereof:

Consolidated Statements of Operations — For the years ended December 31, 2008, 2007, and 2006.

Consolidated Balance Sheets — December 31, 2008 and 2007.

Consolidated Statements of Stockholders’ Equity (Deficit) — For the years ended December 31, 2008, 2007, and 2006.

Consolidated Statements of Cash Flows — For the years ended December 31, 2008, 2007, and 2006.

Notes to Consolidated Financial Statements.

Reports of Independent Registered Public Accounting Firm.

(2)

The following consolidated financial statement schedule of the Company is included on page F-35 hereof:

SCHEDULE II Valuation and Qualifying Accounts

All other financial statements and schedules not listed have been omitted since the required information is included in the consolidated financial statements or the notes thereto, or is not applicable or required.

(3) Exhibits required by Item 601 of Regulation S-K:

EXHIBIT INDEX

Exhibit Number		Description

3.11		Amended and Restated Certificate of Incorporation of Aventine Renewable Energy Holdings, Inc.

3.21		Amended and Restated Bylaws of Aventine Renewable Energy Holdings, Inc.

4.11		Registration Rights Agreement dated as of December 12, 2005 among Aventine Renewable Energy Holdings, Inc., the Investor Holders and the Management Holders named therein

4.2		Indenture, dated as of March 27, 2007, among Aventine Renewable Energy Holdings, Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, N.A. and the form of note (incorporated by reference to Exhibit 4. 1 of Aventine’s Current Report on Form 8-K filed on April 2, 2007)

10.1		Lease Agreement, dated as of October 31, 2006 by and between the Indiana Port Commission and Aventine Renewable Energy – Mt. Vernon, LLC (the “Mt. Vernon Lease Agreement”) (incorporated by reference to Exhibit 10.1 of Aventine’s Annual Report on Form 10-K filed on March 5, 2007)

10.1.1		First Amendment to Mt. Vernon Lease Agreement, dated as of June 14, 2007 (incorporated by reference to Exhibit 10.1.1 of Aventine’s Annual Report on Form 10-K

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	filed on March 5, 2008)

10.1.2	Second Amendment to Mt. Vernon Lease Agreement, dated as of October 18, 2007 (incorporated by reference to Exhibit 10.1.2 of Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

10.1.3	Third Amendment to Mt. Vernon Lease Agreement, dated as of January 26, 2008 (incorporated by reference to Exhibit 10.1.3 of Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

10.1.4	Fourth Amendment to Mt. Vernon Lease Agreement, dated as of June 19, 2008

10.1.5	Fifth Amendment to Mt. Vernon Lease Agreement, dated as of December 18, 2008

10.1.6	Sixth Amendment to Mt. Vernon Lease Agreement, dated as of February 12, 2009

10.21	Rights Agreement dated as of December 19, 2005 between Aventine Renewable Energy Holdings. Inc. and American Stock Transfer & Trust Company, as Rights Agent

10.34	Advance Work Agreement, dated as of March 12, 2007, between the Company and Delta-T Corporation, for the purchase of plant equipment in advance of the completion of negotiations of an engineering, procurement and construction agreement with Kiewit Energy Company

10.44	Pre-engineering, procurement and construction consulting and contracting services contract, dated as of March 17, 2007, between the Company and Kiewit Energy Company, for the performance of certain tasks related to the design and construction of the Company’s proposed Aurora, Nebraska ethanol facility

10.55	Engineering, Procurement and Construction Services Fixed Price Contract, dated as of May 31, 2007, between Aventine Renewable Energy-Aurora West, LLC and Kiewit Energy Company**

10.5.1	Amendment to Engineering, Procurement and Construction Services Fixed Price Contract, dated as of October 1, 2008, between Aventine Renewable Energy – Aurora West, LLC and Kiewit Energy Company

10.5.2	Change Order Number 123108AW to Engineering, Procurement and Construction Services Fixed Price Contract, dated December 31, 2008, between Aventine Renewable Energy – Aurora West, LLC and Kiewit Energy Company

10.5.3	Aurora West EPC Termination Letter from Kiewit Energy Company dated as of March 6, 2009

10.65	Engineering, Procurement and Construction Services Fixed Price Contract, dated as of May 31, 2007, between Aventine Renewable Energy-Mt. Vernon, LLC and Kiewit Energy Company**

10.6.1	Change Order Number 123108MV to Engineering, Procurement and Construction Services Fixed Price Contract, dated December 31, 2008, between Aventine Renewable Energy – Mt. Vernon, LLC and Kiewit Energy Company

10.6.2	Mt. Vernon EPC Termination Letter from Kiewit Energy Company dated as of March 6, 2009

10.75	Parent Guaranty Agreement, dated as of August 6, 2007, between the Company and Kiewit Energy Company

10.85	Parent Guaranty Agreement, dated as of August 6, 2007, between the Company and Kiewit Energy Company

10.9*	Non-Employee Director Compensation Schedule

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10.106*	Form of Performance Stock Unit Award Agreement (2003 Stock Incentive Plan)

10.116*	Form of Stock Option Award Agreement (2003 Stock Incentive Plan)

10.126*	Form of Restricted Stock Award Agreement (2003 Stock Incentive Plan)

10.136*	Form of Non-employee Director Restricted Stock Unit Award Agreement (2003 Stock Incentive Plan)

10.14	Purchase Agreement, dated as of March 21, 2007, among the Company, the subsidiary guarantors named therein and J.P. Morgan Securities, Inc., as representative of several initial purchasers (incorporated by reference to Exhibit 10.1 of Aventine’s Current Report on Form 8-K filed on March 27, 2007)

10.15	Credit Agreement, dated as of March 23, 2007, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 of Aventine’s Current Report on Form 8-K filed on March 26, 2007)

10.15.1	First amendment to Credit Agreement, dated as of March 10, 2009, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent.

10.15.2	Letter agreement dated March 12, 2009, related to the Credit Agreement, dated as of March 23, 2007, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent.

10.16*	Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan (Amended and Restated as of April 16, 2007) (incorporated by reference to Exhibit 10.1 of Aventine’s Current Report on Form 8-K filed on April 16, 2007)

10.172*	Stock Option Award Agreement for Ajay Sabherwal dated November 14, 2005

10.182*	Amendment to Stock Option Award Agreement for Ajay Sabherwal dated December 30, 2005

10.19	Settlement and Release Agreement, dated as of February 27, 2008, by and among the Company, The Williams Companies, Inc. and Williams Energy Services, LLC (incorporated by reference to Exhibit 10.21 of Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

21.1	List of subsidiaries of the Registrant

23.1	Consent of Ernst & Young LLP

31.1	Certificate of Chief Executive Officer of Aventine Renewable Energy Holdings, Inc. pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934

31.2	Certificate of Chief Financial Officer of Aventine Renewable Energy Holdings, Inc. pursuant to Rule 13(a)-14(a) under the Securities Exchange Act of 1934

32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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1 Filed with the registration statement on Form S-1 (333-132860) on March 30, 2006.

2 Filed with the amended registration statement on Form S-1/A (333-132860) on June 13, 2006.

3 Filed with the amended registration statement on Form S-1/A (333-132881) on July 24, 2006.

4 Filed with Aventine’s quarterly report on Form 10-Q on May 9, 2007

5 Filed with Aventine’s quarterly report on Form 10-Q on August 10, 2007.

6 Filed with Aventine’s Current Report on Form 8-K on February 27, 2007.

* Compensatory plan or arrangement.

**	Application was made to the Securities and Exchange Commission to seek confidential treatment of certain provisions. Omitted material for which confidential treatment was requested and granted has been filed separately with the Securities and Exchange Commission.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Pekin, State of Illinois, on the 16th day of March 2009.

AVENTINE RENEWABLE ENERGY HOLDINGS, INC.

By: /s/ William J. Brennan

Name: William J. Brennan

Title: Principal Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Title	Date

By: /s/ Ronald H. Miller	President and Chief Executive	March 16, 2009
Ronald H. Miller	Officer and Director
	(Principal Executive Officer and
	acting Principal Financial Officer)

By: /s/ William J. Brennan	Chief Accounting and Compliance	March 16, 2009
William J. Brennan	Officer (Principal Accounting Officer)

By: /s/ Bobby Latham	Non-Executive Chairman of	March 16, 2009
Bobby Latham	the Board and Director

By: /s/ Leigh J. Abramson	Director	March 16, 2009
Leigh J. Abramson

By: /s/ Theodore H. Butz	Director	March 16, 2009
Theodore H. Butz

By: /s/ Richard A. Derbes	Director	March 16, 2009
Richard A. Derbes

By: /s/ Farokh S. Hakimi	Director	March 16, 2009
Farokh S. Hakimi

By: /s/ Michael C. Hoffman	Director	March 16, 2009
Michael C. Hoffman

By: /s/ Wayne D. Kuhn	Director	March 16, 2009
Wayne D. Kuhn

By: /s/ Arnold M. Nemirow	Director	March 16, 2009
Arnold M. Nemirow

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Statements of Operations

	Year ended December 31,
	2008			2007			2006
(In thousands except per share amounts)
Net sales	$	2,248,301		$	1,571,607		$	1,592,420
Cost of goods sold		2,239,340			1,497,807			1,460,806
Gross profit		8,961			73,800			131,614

Selling, general and administrative expenses		35,410			36,367			28,328
Demobilization costs associated with expansion projects		9,874			-			-
Impairment of plant development costs		1,557			-			-
Other income		(2,936	)		(1,113	)		(3,389	)
Operating income (loss)		(34,944	)		38,546			106,675
Other income (expense):
Loss on sale of auction rate securities		(31,601	)		-			-
Interest expense		(5,077	)		(16,240	)		(9,348	)
Interest income		3,040			12,432			4,771
Loss on early extinguishment of debt		-			-			(14,598	)
Gain (loss) on derivative transactions		17,110			(78	)		3,654
Loss on marketing alliance investment		(4,326	)		-			-
Minority interest		1,230			(1,338	)		(4,568	)
Income (loss) before income taxes		(54,568	)		33,322			86,586
Income tax expense/ (benefit)		(7,472	)		(477	)		31,685
Net income (loss)	$	(47,096	)	$	33,799		$	54,901

Income (loss) per common share—basic	$	(1.12	)	$	0.81		$	1.43
Basic weighted-average number of shares		42,136			41,886			38,411

Income (loss) per common share—diluted	$	(1.12	)	$	0.80		$	1.39
Diluted weighted-average number of common and common equivalent shares		42,136			42,351			39,639

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

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Balance Sheets

	December 31,
	2008			2007
(In thousands except share and per share amounts)
Assets
Current assets:
Cash and equivalents	$	23,339		$	17,171
Short-term investments		-			211,500
Accounts receivable, net of allowance for doubtful accounts of
$272 in 2008 and $48 in 2007		55,888			73,058
Inventories		85,421			81,488
Income taxes receivable		15,135			11,962
Prepaid expenses and other		10,198			12,816
Total current assets		189,981			407,995

Property, plant and equipment, net		107,168			111,867
Construction in process		493,969			226,410
Deferred tax assets		-			1,196
Available for sale securities		673			-
Investment in marketing alliance partners, at cost		1,000			6,000
Other assets		6,668			8,717
Total assets	$	799,459		$	762,185
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	110,903		$	91,871
Senior unsecured 10% fixed-rate notes		300,000			-
Secured revolving credit facility		52,200			-
Accrued interest		7,500			7,500
Accrued liabilities		3,517			3,625
Other current liabilities		9,900			1,622
Total current liabilities		484,020			104,618
Senior unsecured 10% fixed -rate notes		-			300,000
Deferred tax liabilities		2,444			-
Minority interest		-			9,832
Other long-term liabilities		4,199			3,864
Total liabilities		490,663			418,314

Stockholders’ equity:
Common stock, par value $0.001 per share; 185,000,000 shares authorized, 42,970,988 and 41,734,223, shares outstanding as of December 31, 2008 and 2007, respectively, net of 21,548,640 shares held in treasury as of December 31, 2008 and 2007, respectively		43			42
Preferred stock, 50,000,000 shares authorized, no shares issued or outstanding		-			-
Additional paid-in capital		292,984			279,218
Retained earnings		17,839			64,935
Accumulated other comprehensive loss, net		(2,070	)		(324	)
Total stockholders’ equity		308,796			343,871
Total liabilities and stockholders’ equity	$	799,459		$	762,185

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

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity (Deficit)

	Treasury		Common Stock					Additional Paid-In			Retained			Accumulated Other Compre-hensive			Total Stockholders’
(In thousands except number of shares)	Shares		Shares			Amount		Capital			Earnings			Loss			Equity/(Deficit)
Balance at December 31, 2005		21,179,025		35,145,253			35		4,191			(24,013	)		(867	)		(20,654	)
Issuance of common stock				6,410,256			7		260,883						-			260,890
Tax benefit of stock option exercises									3,687									3,687
Stock option exercises				268,707					220									220
Repurchase of common stock for the treasury		50,000		(50,000	)				(1,152	)								(1,152	)
Stock-based compensation				-					6,426									6,426
Issuance of restricted stock awards and amortization of unearned compensation				8,060					52									52
Comprehensive income:
Net income												54,901						54,901
Total comprehensive income																		54,901
Adjustment to initially apply SFAS 158, net of tax of $109				-			-		-			-			(207	)		(207	)
Balance at December 31, 2006		21,229,025		41,782,276			42		274,307			30,888			(1,074	)		304,163
Tax benefit of stock option exercises									180									180
Stock option exercises				201,031					510									510
Repurchase of common stock for the treasury		319,615		(319,615	)				(2,983	)								(2,983	)
Cumulative effect FIN 48 adoption												248						248
Stock-based compensation				-					6,811									6,811
Issuance of restricted stock awards and amortization of unearned compensation				70,531					393									393
Comprehensive income:
Net income												33,799						33,799
Pension and postretirement liability adjustment, net of tax															750			750
Total comprehensive income																		34,549
Balance at December 31, 2007		21,548,640		41,734,223			42		279,218			64,935			(324	)		343,871
Tax withholding for restricted stock vesting				(342	)				(57	)								(57	)
Stock option exercises (forfeitures)									(24	)								(24	)
Stock-based compensation									5,729									5,729
Purchase of minority interest				1,000,000			1		6,618									6,619
Issuance of Common Stock				237,107					1,500									1,500
Comprehensive (loss):
Net (loss)												(47,096	)					(47,096	)
Pension and postretirement liability adjustment, net of tax															(1,746	)		(1,746	)
Total comprehensive (loss)																		(48,842	)
Balance at December 31, 2008		21,548,640		42,970,988		$	43	$	292,984		$	17,839		$	(2,070	)	$	308,796

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

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	Year ended December 31,
(In thousands)	2008			2007			2006
Operating Activities
Net income (loss)	$	(47,096	)	$	33,799		$	54,901
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss related to auction rate securities		31,601			-			-
Depreciation and amortization		15,465			13,265			4,628
Loss on early extinguishment of debt		-			-			14,598
Deferred income taxes		4,489			(6,664	)		(1,177	)
Loss (gain) on disposal of fixed assets		194			(3	)		(110	)
Minority interest		(1,230	)		1,338			4,568
Stock-based compensation expense		5,729			7,204			6,478
Loss on marketing alliance investment		4,326			-			-
Impairment of plant development costs		1,557			-			-
Mark to market of derivative contracts		-			-			839
Other		(546	)		180			3,687
Changes in operating assets and liabilities:
Accounts receivable, net		17,170			6,671			(33,104	)
Income tax receivable		(3,173	)		(5,516	)
Inventories		(3,933	)		(14,437	)		(12,400	)
Prepaid expenses and other		1,951			(8,701	)		(5,315	)
Accounts payable		(8,385	)		14,429			25,914
Demobilization costs for expansion projects		9,874			-			-
Accrued liabilities, including pension and postretirement benefits		7,608			6,016			(4,058	)
Net cash provided by operating activities		35,601			47,581			59,449

Investing Activities
Additions to property, plant and equipment, net		(265,878	)		(235,211	)		(76,499	)
Purchases of short-term securities		-			(690,948	)		(98,925	)
Redemptions of short-term securities		179,899			578,373			-
Investment in marketing alliance partners		-			-			(5,000	)
Increase in restricted cash for plant expansion		-			-			(1,257	)
Release of restricted cash related to repayment of senior notes		-			-			29,762
Use of restricted cash for plant expansion		-			-			31,857
Indemnification proceeds		3,046			-			-
Transaction costs for purchase of Nebraska Energy interest		(200	)		-			-
Proceeds from the sale of fixed asset		-			5			131
Net cash used for investing activities		(83,133	)		(347,781	)		(119,931	)

Financing Activities
Proceeds from issuance of senior unsecured 10% fixed-rate notes		-			300,000			-
Financing fees and expenses paid		-			(8,220	)		-
Net borrowings from (repayments of) revolving credit facilities		52,200			-			(1,514	)
Repayment of senior secured floating rate notes and related premium		-			-			(168,899	)
Distribution to minority shareholders		-			(1,727	)		(3,022	)
Proceeds from issuance of common stock, net		1,500			-			260,890
Repurchase of common stock		-			(2,983	)		(1,152	)
Proceeds from stock option exercises		-			510			220
Net cash provided by financing activities		53,700			287,580			86,523
Net increase (decrease) in cash and equivalents		6,168			(12,620	)		26,041
Cash and equivalents at beginning of year		17,171			29,791			3,750
Cash and equivalents at end of year	$	23,339		$	17,171		$	29,791

Supplemental disclosure of cash flow:
Interest paid	$	31,514		$	15,333		$	11,162
Income taxes paid	$	806		$	11,033		$	33,161

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

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

1. Nature of Operations and Basis of Presentation

Aventine Renewable Energy Holdings, Inc. and Subsidiaries (the “Company,” “Aventine,” “we,” “our,” or “us”) is a producer and marketer of ethanol. Our own production facilities produced 188.8 million gallons of ethanol in 2008 and 192.0 million gallons of ethanol in 2007. 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 2008 and 2007, we distributed 754.3 million gallons and 506.5 million gallons, respectively, of ethanol produced by others. Taken together, we marketed and distributed 936.0 million gallons of ethanol in 2008 and 690.2 million gallons of ethanol in 2007. For the years ended December 31, 2008 and 2007, this represents approximately 11% and 10%, respectively, of the total volume of ethanol sold 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, wet distillers grain with solubles, carbon dioxide and brewers’ yeast.

The accompanying consolidated financial statements on our 2008 financial statements have been prepared assuming that the Company will continue as a going concern. The Company’s independent registered public accounting firm’s report issued in the Annual Report on Form 10-K included an explanatory paragraph describing the existence of conditions that raise substantial doubt about the Company’s ability to continue as a going concern, including significant losses and limited access to additional liquidity. The financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount of and classification of liabilities that may result should the Company be unable to continue as a going concern.

On March 10, 2009, we amended our secured revolving credit facility. The amendment to our secured revolving credit facility requires us to successfully complete an exchange offer of our outstanding

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senior unsecured 10% fixed-rate notes for a like principal amount of a new series of “pay-in-kind” notes. We expect the “pay in kind” notes to (i) require no cash interest prior to April 1, 2010, (ii) require an increase in the interest rate to 12% per annum and (iii) grant a second lien on substantially all of our assets which must be contractually subordinated to the obligations under our secured revolving credit facility. In addition, to encourage holders of our senior unsecured 10% fixed-rate notes to participate in the exchange offer, we expect to need to offer the holders of our senior unsecured 10% fixed-rate notes 8.4 million shares of our common stock (representing approximately 19.9% of our currently outstanding shares of common stock). There can be no assurances, however, that the required percentage or any holders of the senior unsecured 10% fixed-rate notes will agree to an exchange on these terms or at all. Failure to have the holders of 80% of the existing senior unsecured 10% fixed-rate notes commit to participate in the exchange by March 31, 2009 or the failure to consummate the exchange for 90% of the existing senior unsecured 10% fixed-rate notes by April 15, 2009 would be an event of default under our secured revolving credit facility.

In addition, although we suspended construction at both Aurora West and Mt. Vernon during the fourth quarter, 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 $24.4 million at February 28, 2009 are due and payable. 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 existing liquidity constraints.

We remain contractually obligated to complete the suspended plants at Aurora and Mt. Vernon as well as an additional plant at Mt. Vernon capable of producing 110 million gallons of ethanol annually and may incur significant penalties because of our failure to complete these facilities as previously scheduled.

Although we are actively pursuing a number of liquidity alternatives, including the exchange offer for our senior unsecured 10% fixed-rate notes, seeking additional debt and equity financing and a potential sale of all or part of the company, there can be no assurance we will be successful. If we cannot obtain

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sufficient liquidity in the very near-term, we may need to seek to restructure under Chapter 11 of the U.S. Bankruptcy Code.

Effective July 5, 2006, we completed an initial public offering of 9,058,450 shares of our common stock, $0.001 par value, at a gross per share price of $43.00 (the “initial public offering”). The Company sold 6,410,256 shares and received approximately $260.9 million in proceeds, net of discounts and commissions, from this initial public offering. Existing shareholders and management also sold 2,648,194 shares of common stock during the initial public offering, which includes 268,707 shares issued from the exercise of outstanding options. Immediately following our initial public offering, we had 41,831,651 shares of common stock issued and outstanding.

The Company adopted Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards No. 157 (“SFAS 157”), Fair Value Measurements, and FASB Statement of Financial Accounting Standards No. 159 (“SFAS 159”), The Fair Value Option for Financial Assets and Financial Liabilities Including an amendment of FASB Statement No. 115, effective on January 1, 2008. See Note 9 for additional information regarding the adoption of SFAS 157 and SFAS 159 by the Company.

On October 13, 2008, the Company completed its purchase of the 21.58% of Nebraska Energy, LLC (“NELLC”) that it did not already own from Nebraska Energy Cooperative, Inc. (“NEC”). The Company issued 1 million shares of its common stock, with an estimated value of approximately $6.6 million, in exchange for the 21.58% interest. The aggregate value of $6.6 million, or $6.62 per share, was based on the average of Aventine's closing stock price for the four trading days immediately before the acquisition announcement date, the acquisition announcement date and the four trading days immediately after the acquisition announcement date on July 31, 2008. The purchase was accounted for under the purchase method of accounting in accordance with the provisions of SFAS 141.

As a result of our acquisition of the remaining interest in NELLC, NELLC became a guarantor under our secured revolving credit facility and senior unsecured 10% fixed-rate bond indenture on October 22, 2008. As of this same date, all of the assets of NELLC are now collateral under our secured revolving credit facility.

2. Summary of Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Aventine and its subsidiaries. All significant intercompany transactions and accounts have been eliminated in consolidation.

Prior to October 13, 2008, Aventine owned 78.4% of NELLC and the remaining 21.58% of NELLC was owned by NEC. Aventine included in its consolidated financial statements all of the revenues and expenses of NELLC and the interest therein of NEC was reflected as minority interest.

On October 13, 2008, the Company completed its purchase of the 21.58% of NELLC that it did not already own from NEC. The Company issued 1 million shares of its common stock, resulting in a purchase

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price of $6.8 million, including related costs. As a result of the acquisition, the Company no longer accounts for minority interest previously held by NEC.

The purchase was accounted for under the purchase method of accounting in accordance with the provisions of SFAS No. 141. The purchase accounting allocation related to the acquisition has been recorded in the accompanying consolidated financial statements as of, and for the period subsequent to October 13, 2008. The estimated fair value of assets acquired and liabilities assumed was $10.4 million and $1.7 million, respectively. The excess of the fair value of the acquired net assets over the purchase price was allocated to reduce the carrying values of net book value of property, plant, and equipment by $1.9 million.

Uses of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as amounts of revenue and expenses during the reporting periods. Actual results could differ from those estimates.

Industry Segments

We operate in one reportable segment, the manufacture and marketing of fuel-grade ethanol.

Revenue Recognition

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Cash Equivalents

We consider all highly liquid short-term investments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value.

Short-Term Investments

At December 31, 2008, we held no short-term investments. At December 31, 2007, we had invested $211.5 million in taxable auction rate securities (“ARS”) which we classified as current assets.

Prior to December 31, 2007, we began to exit our position in these securities and continued to do so in early 2008. During 2008, we liquidated all of the auction rate securities we held, incurring a loss of $31.6 million.

Accounts Receivable and Concentration of Credit Risk

Accounts receivable are recorded on a gross basis, with no discounting, less an allowance for doubtful accounts. Management estimates the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers, and the amount and age of past due accounts.

The Company sells 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 47% and 67% of our consolidated sales revenue for the years ended December 31, 2008 and 2007, respectively. We had no customers that accounted for 10% or more of our consolidated revenue in 2008. In 2007, our three largest customers accounted for approximately 15%, 11% and 10% of our consolidated revenue.

Inventories

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. Inventory costs include expenditures incurred bringing inventory to its existing condition and location.

Property, Plant and Equipment

Newly acquired land, buildings and equipment are carried at cost less accumulated depreciation. Depreciation is provided over the estimated useful lives of the assets, generally on the straight-line method for financial reporting purposes (furniture and fixtures 3 – 20 years, machinery and equipment 5 – 25 years, storage tanks 25 – 30 years, and buildings and improvements 20 – 45 years), and on accelerated methods for tax purposes.

In connection with the acquisition of the Company by MSCP, the excess of the fair value of the net assets over the purchase price was allocated to reduce the carrying values of the non-current assets, including property, plant and equipment.

Impairment of Long-Lived Assets

Long-lived assets are evaluated for impairment under the provisions of Statement of Financial Accounting Standards No. 144 (“SFAS 144”), Accounting for the Impairment or Disposal of Long-Lived

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Assets. When facts and circumstances indicate that long-lived assets used in operations may be impaired, and the undiscounted cash flows estimated to be generated from those assets are less than their carrying values, an impairment charge is recorded equal to the excess of the carrying value over fair value.

Investments in Marketing Alliances

We have made minority investments in other ethanol producers. Investments made by the Company in other ethanol producers after May 31, 2003 were recorded on the cost basis and aggregated $1 million and $6 million as of December 31, 2008 and 2007 respectively. Investments made by our predecessor company in one ethanol plant prior to May 31, 2003 were written down to zero as part of the purchase price allocation upon the acquisition of the Company by MSCP.

In 2008, Indiana Bio-Energy, LLC (“IBE”), one of our cost basis investees, was acquired 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 publically held company whose shares are traded on the NASDAQ national market, and our $5.0 million original investment was converted to 365,999 shares of GPRE stock. On October 15, 2008, we recorded a loss of $2.8 million on the exchange and reduced the value of our investment from $5.0 million to $2.2 million, which was the market price of the GPRE shares at that date. As our investment in GPRE shares is considered an available for sale investment in accordance with Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities (“SFAS 115”), we recognized an other than temporary loss of $1.5 million on December 31, 2008. In making our determination that the loss in GPRE stock was other than temporary, we considered our lack of ability and intent to hold this security to recover its value given our current liquidity situation. The market value of our investment in GPRE at December 31, 2008 based upon the closing price of GPRE stock on the last trading day of 2008 was $0.7 million.

Subsequent to December 31, 2008, we sold our interest in Ace Ethanol, LLC and Granite Falls Energy, LLC, recording gains totaling $1.0 million. After taking into account the sales of equity interests which occurred in January 2009, the remaining investments we have in other ethanol plants consist of 365,999 shares of common stock in GPRE reported at quoted market prices as an available for sale security and 131,000 membership shares in Advanced BioEnergy, LLC.

Unearned Revenue

In 2005, the Company received $3 million from a marketing alliance partner to amend the marketing agreement with this partner. The Company recorded this amount as deferred revenue and began recognizing the related revenue over the life of the agreement which extended through August 2012. The marketing agreement was terminated effective October 1, 2008, and the remaining deferred revenue of $1.6 million was recognized as income in 2008.

Employment-Related Benefits

Employment-related benefits associated with pensions and postretirement health care are expensed as actuarially determined. The recognition of expense is impacted by estimates made by management, such as discount rates used to value certain liabilities, investment rates of return on plan assets, increases in future wage amounts and future health care costs. The Company uses third-party specialists to assist management in appropriately measuring the expense and liabilities associated with employment-related benefits.

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We determine our actuarial assumptions for the 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 plans’ 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.

Income Taxes

Earnings Per Common Share

Basic earnings per share is computed by dividing net income by the weighted-average number of common shares outstanding. Diluted earnings per share is calculated by including the effect of all dilutive securities, including stock options. To the extent that stock options and unvested restricted stock are anti-dilutive, they are excluded from the calculation of diluted earnings per share.

Derivatives and Hedging Activities

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

We apply the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and by Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (hereinafter collectively referred to as “SFAS 133”), for the Company’s derivatives. These futures contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative instruments is recognized in other current assets or liabilities in the Consolidated Balance Sheet, net of any cash received from the brokers.

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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, natural gas and forward sales of ethanol as normal purchases and normal sales under SFAS 133.

Fair Values of Financial Instruments

We use the following methods in estimating fair value disclosures for financial instruments:

Cash and equivalents, short-term investments, accounts receivable and accounts payable: The carrying amount reported in the Consolidated Balance Sheets approximates fair value.

Revolving credit facility and long-term debt: The carrying amount of our borrowings under our revolving credit facilities approximates fair value. The fair value of our senior unsecured 10% fixed -rate notes are based upon quoted closing market prices at year-end.

Commodity derivatives: Commodity derivative instruments held by the Company consist primarily of futures contracts, swaps and option contracts. The fair value of these commodity derivative instruments are determined by reference to quoted market prices.

Available for sale securities: Available for sale securities consist of a common stock investment in exchanged traded securities and the fair value of these securities is determined using quoted market prices at year-end.

Environmental Expenditures

Environmental expenditures that pertain to our current operations and relate to future revenue are expensed or capitalized consistent with our capitalization policy. Expenditures that result from the remediation of an existing condition caused by past operations, and that do not contribute to future revenue, are expensed.

Research and Development Costs

Expenditures relating to the development of new products and processes, including significant improvements and refinements to existing products, are expensed as incurred. The amounts charged to expense were approximately $0.1 million, $0.3 million and $0.2 million for the years ended 2008, 2007 and 2006, respectively

Recent Accounting Pronouncements

In June 2008, the FASB issued FASB Staff Position (FSP) EITF Issue No. 03-6-1 (“FSP EITF 03-6-1”), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. FSP EITF 03-6-1 requires that unvested share-based payment awards that contain rights to receive non-forfeitable dividends or dividend equivalents to be included in the two-class method of computing earnings per share as described in SFAS No. 128, Earnings per Share. This FSP was effective for financial statements issued for fiscal years beginning after Dec. 15, 2008, and interim periods within those years. Accordingly, we will adopt FSP EITF 03-6-1 in fiscal year 2009. We are currently evaluating the impact of FSP EITF 03-6-1 on the consolidated financial statements.

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3. Related Party Transactions

As of May 30, 2003, the date we were acquired from the William’s Companies, Aventine’s principal shareholders were the Morgan Stanley Capital Partners (“MSCP”) funds. Morgan Stanley Investment Management, Inc. subsequently entered into definitive agreements under which Metalmark Subadvisor LLC, an affiliate of Metalmark, an independent private equity firm established by former principals of MSCP, manages the 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 the applicable MSCP funds on a sub-advisory basis. The MSCP funds owned 27.5% of our common stock at December 31, 2008.

Two of the Company’s directors are currently employees of Metalmark. Our amended and restated certificate of incorporation provides that directors may not be removed from office by the stockholders except for cause and only by an affirmative vote of the holders of not less than 85% of the voting power of the issued and outstanding shares of our capital stock entitled to vote generally at an election of directors.

In exchange for providing professional expertise, services, consulting, or advice in accordance with an agreement entered into with one of the MSCP funds prior to the MSCP funds’ acquisition of the Company, the directors received Class B units in Aventine Holdings LLC (Aventine Holdings, LLC is the investment vehicle in which MSCP holds the Common Stock of the Company). Class B units have no voting rights, participate in distributions only after a specified threshold is met, and are subject to certain additional limitations.

Aventine maintains minority investments in some marketing alliance partners. Total purchases from these plants aggregated $251.6 million, $240.9 million and $228.2 million, for the years ended December 31, 2008, 2007 and 2006, respectively. These transactions were recorded at market prices and under normal commercial terms. As of December 31, 2008, we had recorded in accounts payable approximately $21.0 million owed to marketing alliance partners where we had an ownership interest. These funds represent amounts owed to these alliance partners for purchased ethanol.

During 2006, we received a $1.3 million one-time special cash dividend from Heartland Grain Fuels, a marketing alliance partner in which we hold an ownership interest, prior to their being acquired by Advanced BioEnergy, LLC which was recorded in other operating income.

4. Inventories

Inventories are as follows:

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	December 31,
(In thousands)	2008	2007

Finished products	$76,968	$73,530
Work-in-process	2,568	2,035
Raw materials	3,600	2,757
Supplies	2,285	3,166
Totals	$85,421	$81,488

5. Prepaid Expenses and Other

Prepaid expenses and other are as follows at December 31:

(In thousands)	2008	2007

Prepaid motor fuel taxes and other miscellaneous receivables	$ 3,667	$ 5,061
Fair value of derivative instruments	1,521	4,013
Prepaid insurance	1,435	1,107
Deferred income taxes current	1,593	853
Prepaid ethanol	512	1,050
Prepaid benefits	364	-
Other prepaid expenses	1,106	732
Totals	$10,198	$12,816

6. Fair Value Measurements

SFAS 157

The Company adopted SFAS 157 effective January 1, 2008 for financial assets and liabilities measured at fair value on a recurring basis. SFAS 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. There was no impact of adoption of SFAS 157 to the consolidated balance sheet or statement of operations. SFAS 157 establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires that fair value measurements be classified and disclosed in one of the following three categories:

·	Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

·	Level 2: Quoted prices in markets that are not active, for inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability;

·	Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

The Company elected to implement SFAS 157 with the one-year deferral permitted by FASB Staff Position No. FAS 157-2 (“FSP 157-2”), for nonfinancial assets and nonfinancial liabilities, except for those items that are recognized or disclosed at fair value in the financial statements on a recurring basis. The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination.

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In October 2008, the FASB issued FSP 157-3 (“FSP 157-3”), Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active. FSP 157-3 clarifies the application of SFAS No. 157 in a market that is not active, and addresses application issues such as the use of internal assumptions when relevant observable data does not exist, the use of observable market information when the market is not active, and the use of market quotes when assessing the relevance of observable and unobservable data. FSP 157-3 is effective for all periods presented in accordance with SFAS No. 157. There was no impact upon the adoption of FSP 157-3 to the consolidated financial statements or the fair values of our financial assets and liabilities.

The following table summarizes the valuation of our financial instruments which are carried at fair value by the above SFAS 157 pricing levels as of December 31, 2008:

			Fair Value Measurements at the Reporting Date Using
	Fair Value at December 31, 2008		Quoted Prices in Active Markets Using Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

Cash and cash equivalents	$	23,339	$	23,339		-		-
Commodity futures contracts	$	5,988	$	5,988		-		-
Available for sale securities	$	673	$	673		-		-

The following table represents a reconciliation of the change in assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the year ended December 31, 2008.

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Balance at December 31, 2007	$	-
Net transfers to Level 3 category from Level 1 category		127,200
Sales of Level 3 category assets		97,099
Total realized losses recognized in net income		(30,101	)
Balance at December 31, 2008	$	-

In 2008, the Company recorded losses from Level 3 assets (auction rate securities) of $30.1 million. In addition, the Company also sold auction rate securities prior to these assets being classified as Level 3 assets incurring a loss of $1.5 million. The total losses incurred by the Company in 2008 related to auction rate securities were $31.6 million. This loss is included in “loss on sale of auction rate securities” in the Condensed Consolidated Statement of Operations. The Company holds no auction rate securities as of December 31, 2008.

The fair value of our derivative contracts are primarily measured based on closing market prices for commodities as quoted on the Chicago Board of Option Trading (“CBOT”) or the New York Mercantile Exchange (“NYMEX”).

The Company recorded net gains of $17.1 million and net losses of $0.1 million, respectively, for the full-years ended December 31, 2008 and 2007 under “other non-operating income” in the Condensed

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Consolidated Statements of Operations for the changes in the fair value of its derivative financial instrument positions.

The Company recorded a loss of $4.3 million for the year-ended December 31, 2008 relating to an investment in a marketing alliance partner, which investment is now classified as available for sale. The 2008 loss is recorded in the Condensed Consolidated Statements of Operations as “Loss on marketing alliance investment”.

SFAS 159

The Company adopted SFAS 159 effective January 1, 2008. We have not elected the fair value option for any of our financial assets or liabilities.

The carrying value of other financial instruments, including cash, accounts receivable, accounts payable and accrued liabilities and amounts owed under our secured revolving credit facility approximate fair value due to their short maturities or variable-rate nature of the respective balances. The following table presents the other financial instruments that are not carried at fair value but which require fair value disclosure as of December 31, 2008 and 2007.

	As of December 31, 2008						As of December 31, 2007
	Carrying Value			Fair Value			Carrying Value			Fair Value
Investment in other ethanol producers, at cost	$	1,000			n/a		$	6,000			n/a
Commodity margin deposits	$	1,521		$	1,521		$	4,013		$	4,013
Long-term debt	$	(300,000	)	$	(49,500	)	$	(300,000	)	$	(274,500	)

Prior to 2008, the Company’s investments in minority positions of other ethanol operating companies have historically been recorded at cost, as these investments were in non-publicly traded companies for which it was not practical to estimate a fair value. In October 2008, one of the investments made by the Company was exchanged for shares in a NASDAQ listed publicly traded entity which we recorded at fair value. The Company monitors its remaining cost basis investments for impairment by considering current factors, including the economic environment, market conditions, operational performance and other specific factors relating to the business underlying the investment, and records reductions in carrying values when necessary. Any impairment loss is reported under “Other income (expense)” in the consolidated statement of operations.

The fair value of our senior unsecured 10% fixed-rate notes are based upon quoted closing market prices at the end of the period.

7. Property, Plant and Equipment

Property, plant and equipment at December 31 are as follows:

(In thousands)	2008			2007

Land and improvements	$	1,659		$	1,659
Building and improvements		5,391			5,300
Machinery and equipment		132,700			122,788
Storage tanks		3,108			3,108
Furniture and fixtures		25			25
Less accumulated depreciation		(35,715	)		(21,013	)
Totals	$	107,168		$	111,867

Construction-in-progress	$	493,969		$	226,410

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Depreciation expense in 2008, 2007 and 2006 was $14.5 million, $12.6 million and $3.7 million, respectively.

In 2008, we recorded an impairment charge of $1.6 million relating to our decision to indefinitely suspend development of our Pekin III facility.

Construction-in-progress at December 31, 2008 includes $27.4 million of capitalized costs which are due to the Company’s primary construction contractor, Kiewit Energy Company. This obligation is due in installments through June 2009. Subsequent to December 31, 2008, the Company ceased making payments to Kiewit on amounts owed and Kiewit has filed liens against the construction projects. In addition, on March 9, 2009, the Company received a notice from Kiewit cancelling the engineering, construction and procurement contracts for the Aurora West and Mt. Vernon expansion projects, 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 $24.4 million at February 28, 2009 are due and payable. Additionally, cancellation of these contracts causes a covenant violation under our senior notes as discussed in Notes 10 and 11.

The 2008 construction accrual has been treated as a non-cash item in the accompanying Statement of Cash Flows.

8. Other Assets

Other assets at December 31 are as follows:

(In thousands)	2008		2007

Deferred debt issuance costs	$	6,668	$	7,533
Funded status of pension plan		-		1,184
Totals	$	6,668	$	8,717

Deferred debt issuance costs are subject to amortization. Remaining deferred debt issuance costs of $6.0 million related to our senior unsecured 10% fixed-rate notes will be amortized utilizing a method which approximates the effective interest method over the remaining life of 8.25 years, resulting in amortization expense of $0.7 million yearly, unless such notes are extinguished sooner. Remaining deferred debt issuance costs of $0.7 million related to our secured revolving credit facility will be written off in 2009 as a result of the amendment of our secured revolving credit facility as discussed in Note 10.

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9. Other Current Liabilities

Other current liabilities are as follows at December 31:

(In thousands)	2008		2007

Deferred revenue	$	8,425	$	-
Accrued sales taxes		339		184
Deferred income taxes		507		379
Accrued property taxes		575		578
Current portion of unearned commission		-		424
Other accrued operating expenses		54		57
Totals	$	9,900	$	1,622

10. Secured Revolving Credit Facility

At December 31, 2008 and 2007, our liquidity facility consisted of a 5 year secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent and a lender, of up to $200 million, subject to collateral availability, which, under certain circumstances, could be increased up to $300 million. Our secured revolving credit facility included a $25 million sub-limit for letters of credit. The credit facility expires in March 2012, and is secured by substantially all of the Company’s assets, with the exception of the assets of Nebraska Energy, LLC prior to the Company’s purchase of the remaining interest in October 2008.

Collateral availability is determined via a borrowing base, which includes a percentage of eligible receivables and inventory, and no more than $50 million of property, plant and equipment. The amount of property, plant and equipment which can be included in the borrowing base reduces at a rate of $1.8 million each quarter beginning with the quarter ended December 31, 2007. At December 31, 2008, the amount of property, plant and equipment which was eligible for inclusion in the calculation of the borrowing base was $41.1 million.

Borrowings generally bear interest, at our option, at the following rates (i) the Eurodollar rate or the LIBO rate plus a margin between 1.25% to 1.75%, depending on the average availability, or (ii) the greater of the prime rate or the federal funds rate plus 0.50%, plus a margin between 0.00% to 0.50%, depending on the average availability. Accrued interest is payable monthly on outstanding principal amounts, provided that accrued interest on Eurodollar loans is payable at the end of each interest period, but in no event less frequently than quarterly. In addition, fees and expenses are payable based on unused borrowing availability (0.25% to 0.50% per annum, depending on the average availability), outstanding letters of credit (4.625%) and administrative and legal costs.

Availability under our secured revolving credit facility is subject to customary conditions, including the representations and warranties, the absence of any material adverse change and covenants, which, among other things, limit our ability to incur additional indebtedness and liens; enter into transactions with affiliates; make acquisitions; pay dividends; redeem or repurchase capital stock or senior notes; make investments or loans; make negative pledges; consolidate, merge or effect asset sales; or change the nature of our business. In addition, if availability under the facility falls below $50 million, we must maintain a coverage ratio of EBITDA (as defined under the agreement) to interest expense of 1.1 to 1.

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other agreements contained in the transaction documents; inaccuracies in representations and warranties; certain defaults, termination events or similar events; certain defaults with respect to any other Company indebtedness in excess of $5.0 million; certain bankruptcy or insolvency events; the rendering of certain judgments in excess of $5.0 million; certain ERISA events; certain change in control events and the defectiveness of any liens under the secured revolving credit facility. Obligations under the secured revolving credit facility may be accelerated upon the occurrence of an event of default.

We had $52.2 million in borrowings outstanding under our secured revolving credit facility at December 31, 2008, and $22.2 million of standby letters of credit outstanding, thereby leaving no additional borrowing availability under our secured revolving credit facility as of that date. At December 31, 2007, we had no borrowings outstanding under our secured revolving credit facility, and $16.9 million of standby letters of credit outstanding, thereby leaving approximately $122.6 million in additional borrowing availability under our secured revolving credit facility as of that date.

On March 10, 2009 we amended our existing secured revolving credit facility. The amended liquidity facility consists of a secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent and a lender. The revolving commitment declines from $200 million under the original facility to initially $75 million under the amended facility, and further reduces to $60 million on April 1, 2009 and $50 million on May 1, 2009 and thereafter (subject to collateral availability). The amended liquidity facility continues to include a $25 million sub-limit for letters of credit. The amended credit facility expiration date is now March 1, 2010, and the facility continues to be secured by substantially all of the Company’s assets. The default under our 10% fixed rate notes related to the Kiewit liens constitutes an event of default under our secured revolving credit facility. We have obtained a waiver of this event of default from the lenders under our secured revolving credit facility until April 15, 2009.

Collateral availability under the amended facility continues to be determined via a borrowing base, which includes a percentage of eligible receivables and inventory, and no more than $10 million of property, plant and equipment. The amount of property, plant and equipment which can be included in the borrowing base reduces at a rate of $1.0 million each month beginning in September 1, 2009.

Borrowings on the amended facility generally bear interest, at our option, at the following rates (i) the Eurodollar rate or the LIBO rate plus a margin of 4.5%, with a LIBO rate minimum of 3%, or (ii) the greater of the prime rate or the federal funds rate plus 0.50% (with a minimum rate of LIBOR plus 2.25%), plus a margin of 3.25%. Accrued interest is payable monthly on outstanding principal amounts, provided that accrued interest on Eurodollar loans is payable at the end of each interest period, but in no event less frequently than quarterly. In addition, the following fees are also applicable: an unused commitment fee of 0.50% on unused borrowing availability, an outstanding letters of credit fee of 4.625%, and administrative and legal costs.

Availability under the amended secured revolving credit facility continues to be subject to customary conditions, including the representations and warranties, the absence of any material adverse change and meeting certain covenants, which, among other things, limit our ability to incur additional indebtedness and liens; enter into transactions with affiliates; make acquisitions; pay dividends; redeem or repurchase capital stock or senior notes; make investments or loans; make negative pledges; consolidate, merge or effect asset sales; or change the nature of our business.

In addition, the amendment to our secured revolving credit facility requires us to successfully complete an exchange offer of our outstanding senior unsecured 10% fixed-rate notes for a like principal amount of a new series of “pay-in-kind” notes. Failure to have the holders of 80% of the existing senior unsecured 10% fixed-rate notes commit to participate in the exchange by March 31, 2009 or the failure to

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consummate the exchange for 90% of the existing senior unsecured 10% fixed-rate notes by April 15, 2009 would be an event of default under our secured revolving credit facility.

As of March 12, 2009, $22.2 million in letters of credit and $16.5 million in revolving loans were outstanding under the amended secured revolving credit facility. After giving effect to the recent amendment to our secured revolving credit facility, we had $0.7 million of cash and $6.6 million of additional borrowing availability under the secured revolving credit facility as of such date. All of our cash receipts are automatically applied to reduce amounts outstanding under our amended secured revolving credit facility and to cash collateralize our letters of credit. As we continue to reduce the number of gallons of ethanol we sell and hold in inventory, working capital available to support borrowings under our secured revolving credit facility will reduce proportionately.

11. Senior Notes

At December 31, 2008, the Company had outstanding $300 million aggregate principal amount of senior unsecured 10% fixed-rate notes due April 2017 (“Notes”). The Notes were issued pursuant to an indenture, dated as of March 27, 2007, between us and Wells Fargo Bank, N.A., as trustee. The Notes are general unsecured obligations of the Company and certain of its guarantor subsidiaries, initially limited to $300 million aggregate principal amount. We may, subject to the covenants and applicable law, issue additional notes under the indenture. Any additional notes would be treated as a single class with the previously issued Notes for all purposes under the indenture.

The Notes have interest payments due semi-annually on April 1 and October 1 of each year. We do not expect to have adequate liquidity to satisfy the $15 million interest payment due on April 1, 2009. The Notes are redeemable after the dates and at prices (expressed in percentages of principal amount on the redemption date), as set forth below:

Year	Percentage
April 1, 2012	105.000%
April 1, 2013	103.330%
April 1, 2014	101.667%
April 1, 2015 and thereafter	100.000%

In addition, at any time prior to April 1, 2010, we may redeem up to 35% of the principal amount of the Notes from time to time originally issued with the net cash proceeds of one or more sales of qualifying capital stock of the Company at a redemption price of 110% of the principal amount, together with accrued and unpaid interest to the redemption date, provided that at least 65% of the aggregate principal amount of the Notes originally issued remains outstanding immediately after such redemption and notice of any such redemption is mailed within 60 days of each such sale of capital stock. The term of the Notes also contain restrictive covenants that limit our ability to, among other things, incur additional debt, sell or transfer assets, make investments or guarantees, enter into transactions with shareholders and affiliates, and pay future dividends.

On August 10, 2007, we exchanged all of the outstanding Notes for an issue of registered senior unsecured 10% fixed-rate notes, with terms identical to the Notes.

The amendment to our secured revolving credit facility requires us to successfully complete an exchange offer of our outstanding Notes for a like principal amount of a new series of “pay-in-kind” notes. We expect the “pay in kind” notes to (i) require no cash interest prior to April 1, 2010, (ii) require an increase in the interest rate to 12% per annum and (iii) grant a second lien on substantially all of our assets

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which must be contractually subordinated to the obligations under our secured revolving credit facility. In addition, to encourage holders of our senior unsecured 10% fixed-rate notes to participate in the exchange offer, we expect to need to offer the holders of our senior unsecured 10% fixed-rate notes 8.4 million shares of our common stock (representing approximately 19.9% of our currently outstanding shares of common stock). There can be no assurances, however, that the required percentage or any holders of the Notes will agree to an exchange on these terms or at all. Failure to have the holders of 80% of the existing Notes commit to participate in the exchange by March 31, 2009 or the failure to consummate the exchange for 90% of the existing Notes by April 15, 2009 would be an event of default under our secured revolving credit facility.

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 $24.4 million at February 28, 2009 are due and payable. Because our obligations to Kiewit are past due, the liens securing these obligations violate the terms of the Notes and constitute a default thereunder. Unless such default is cured through payment, the release of the liens, a negotiated resolution or otherwise, the holders of the Notes may accelerate the $300 million principal amount thereof upon 60 days notice. As a result, the $300 million principal amount outstanding has been classified as a current liability in the Consolidated Balance Sheet.

The Company previously had outstanding $160 million of senior secured floating rate notes due 2011. In 2006, we paid $169.8 million (including premiums) from the funds received in our initial public offering to fund the repurchase of $160 million aggregate principal amount of the senior secured floating rate notes.

12. Other Long-Term Liabilities

Other long-term liabilities at December 31 are as follows:

(In thousands)	2008		2007

Unfunded postretirement benefit obligation	$	1,834	$	2,339
Unfunded pension liability		1,491		-
Unearned commission		-		1,525
Reserve for uncertain tax positions (See Note 17)		848		-
Accrued interest on Uncertain tax positions (See Note 17)		26		-
Totals	$	4,199	$	3,864

13. Interest Expense

The following table summarizes interest expense:

	Year Ended December 31,
(in thousands)	2008			2007			2006

Interest expense – bonds	$	30,000		$	22,833		$	10,230
Interest expense – revolving credit facility		1,514			703			317
Capitalized interest		(26,437	)		(7,296	)		(1,199	)
Total interest expense	$	5,077		$	16,240		$	9,348

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14. Retirement and Pension Plans

We have 401(k) plans covering substantially all of our employees. We provide, at our discretion, a match of employee salaries contributed to the plans. We recorded expense with respect to these plans of $1.1 million in 2008, $1.0 million in 2007, and $1.3 million in 2006.

Qualified Retirement Plan

We have a defined benefit pension plan (Retirement Plan) that is noncontributory which covers unionized employees at our Pekin, Illinois facility who fulfill minimum age and service requirements. Benefits are based on a prescribed formula based upon the employee’s years of service. The Retirement Plan was amended in 2006 to increase the Company’s contribution rate for years of service in response to provisions in a new labor agreement between the Company and its unionized employees, which became effective in June 2006.

The average asset allocations for our Retirement Plan at December 31 are as follows:

	2008			2007

Equity securities		54	%		57	%
Debt securities		36			31
Cash and equivalents		10			12
Total		100	%		100	%

The Company’s Pension Committee is responsible for overseeing the investment of pension plan assets. The Pension Committee is responsible for determining and monitoring the appropriate asset allocations and for selecting or replacing investment managers, trustees, and custodians. The pension plan’s current investment target allocations are 50% equities, 30% debt and 20% stable funds. The Pension Committee reviews the actual asset allocation in light of these targets periodically and rebalances investments as necessary. The Pension Committee also evaluates the performance of investment managers as compared to the performance of specified benchmarks and peers and monitors the investment managers to ensure adherence to their stated investment style and to the plan’s investment guidelines.

On December 31, 2008, the annual measurement date, our Retirement Plan had a projected accumulated benefit obligation of $8.8 million and the fair value of the plan assets was $7.3 million. In accordance with SFAS 158, we recognized the underfunded status of the plan by recording an accrued pension liability of $1.5 million. The offsetting amount charged to accumulated other comprehensive loss adjusts the total in other comprehensive loss to $4.0 million pre-tax, which is the amount of the net unrecognized actuarial loss and unrecognized prior service cost.

Items not yet recognized as a component of net periodic pension cost and amounts recognized in the Consolidated Balance Sheets are as follows at December 31:

(In thousands)	2008			2007

Funded/(Unfunded) status	$	(1,491	)	$	1,184

Amounts recognized in
Non-current assets		-			1,184
Long-term liabilities	$	(1,491	)		-
Deferred taxes		1,550			208
Accumulated other comprehensive loss:
Unamortized prior service cost		490			532
Unamortized net actuarial loss/(gain)		3,483			(5	)

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The amount of unamortized prior service costs that will be recognized as a component of net periodic pension cost in 2009 is expected to be $42 thousand. The amount of unamortized net actuarial losses that will be recognized as a component of net periodic pension cost in 2009 is expected to be $180 thousand.

Certain assumptions utilized in determining the benefit obligations for the Retirement Plan for the years ended December 31 are as follows:

	2008	2007
Discount rate	6.00%	6.50%

A summary of the components of net periodic pension cost for the Retirement Plan for the years ended December 31 is as follows:

(In thousands)	2008			2007			2006

Service cost	$	288		$	351		$	285
Interest cost		496			497			430
Expected return on plan assets		(716	)		(720	)		(512	)
Amortization of net actuarial loss		-			25			47
Amortization of prior service cost		42			42			-
Net periodic pension cost	$	110		$	195		$	250

We recognized no amortization of our net actuarial loss in 2008, as losses as of January 1, 2008 did not exceed 10% of our projected benefit obligation.

Certain assumptions utilized in determining the net periodic benefit cost for the years ended December 31 are as follows:

	2008	2007	2006

Discount rate	6.50%	5.75%	5.50%
Expected long-term rate of return on plan assets	7.75%	8.50%	8.50%

The following table sets forth a reconciliation of the projected benefit obligation for the years ended December 31:

(In thousands)	2008			2007

Benefit obligation at the beginning of the year	$	7,815		$	8,607
Service costs		288			351
Interest costs		496			497
Actuarial (gain)/loss		568			(1,275	)
Benefits paid		(361	)		(365	)
Benefit obligation at the end of the year	$	8,805		$	7,815

At December 31, 2008 and 2007, the projected benefit obligation and the accumulated benefit obligation are equal.

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The actuarial loss for the year ended December 31, 2008 results primarily from the decrease in the discount rate used in the calculation of the benefit obligation to 6.00% from 6.50%. The actuarial gain for the year ended December 31, 2007 results primarily from the increase in the discount rate used in the calculation of the benefit obligation to 6.50% from 5.75%.

The following table sets forth a reconciliation of the plan assets for the years ended December 31:

(In thousands)	2008			2007

Fair value of plan assets at the beginning of the year	$	8,999		$	8,455
Employer contributions		880			500
Actual return on plan assets		(2,204	)		408
Benefits paid		(361	)		(364	)
Fair value of plan assets at the end of the year	$	7,314		$	8,999

In 2009, we anticipate making contributions totaling $1.0 million.

The expected future benefits payments for the plan are as follows:

(in thousands)
2009	$ 411
2010	437
2011	453
2012	466
2013	495
2014 – 2018	2,801

15. Postretirement Benefit Obligation

We sponsor a health care plan and life insurance plan (“Postretirement Plan”) that provides postretirement medical benefits and life insurance to certain “grandfathered” unionized employees. The plan is contributory, with contributions required at the same rate as active employees. Benefit eligibility under the plan reduces at age 65 from a defined benefit to a defined dollar cap based upon years of service.

On December 31, 2008, the annual measurement date, our Postretirement Plan had an accumulated benefit obligation of $1.9 million, which is less than the accumulated benefit obligation at December 31, 2007 of $2.3 million. The Postretirement Plan is unfunded and has no assets.

Items not yet recognized as a component of net periodic pension cost and recognized in the Consolidated Balance Sheets are as follows at December 31:

(In thousands)	2008			2007

Unfunded status	$	(1,863	)	$	(2,339	)

Amounts recognized in:
Current liabilities		(29	)		(29	)
Long-term liabilities		(1,834	)		(2,310	)
Deferred taxes		(226	)		4
Accumulated other comprehensive (income)/loss:
Unamortized net actuarial (gain)/loss		(579	)		10

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We expect to recognize an amortization of net actuarial gain of $28 thousand in 2009.

Net periodic postretirement benefit cost for the years ended December 31 includes the following components:

(In thousands)	2008			2007		2006

Service cost	$	76		$	151	$	153
Interest cost		106			135		122
Recognized net actuarial gain (loss)		(38	)		-		10
Net periodic postretirement benefit cost	$	144		$	286	$	285

The change in benefit obligation for the years ended December 31 includes the following components:

(In thousands)	2008			2007

Benefit obligation at the beginning of the year	$	2,339		$	2,275
Service cost		76			151
Interest cost		106			135
Actuarial loss/(gain)		(627	)		(192	)
Benefits paid		(30	)		(30	)
Benefit obligation at the end of the year	$	1,863		$	2,339

The weighted-average discount rate used to determine net periodic postretirement benefit cost was 6.5% at December 31, 2008 and 6.0% at December 31, 2007.

The expected future benefits payments for the plan are as follows:

(in thousands)
2009	$ 29
2010	28
2011	35
2012	37
2013	37
2014 – 2018	527

For purposes of determining the cost and obligation for pre-Medicare postretirement medical benefits, a 13.9% annual rate of increase in the per capita cost of covered benefits (i.e., health care trend rate) was assumed for the plan in 2008, declining to a rate of 5.35% in 2016. Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one percent change in the assumed health care cost trend rate would have had the following effects:

(In thousands)	1% Increase		1% Decrease

Effect on total of service and interest cost components	$	13	$	(11	)
Effect on postretirement benefit obligation	$	143	$	(120	)

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16. Environmental Remediation and Contingencies

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Federal and state environmental authorities have been investigating alleged excess volatile organic compounds emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities. The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility. If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar investigation at our Nebraska facility due to the larger size of the Illinois wet mill facility. 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. In February 2008, we received a $3.0 million indemnification payment from the former owner of our Nebraska facility relating to the cost of installing environmental controls at that facility in connection with an April 2005 consent decree with state authorities.

17. Income Taxes

The provision for income taxes for the years ended December 31 consists of the following:

(In thousands)	2008			2007			2006

Current expense (benefit)		(10,616	)		5,749			32,754
Deferred expense (benefit)		3,118			(5,852	)		(1,069	)
Interest income (expense)		26			(374	)		-
Total income tax expense/ (benefit)		(7,472	)		(477	)		31,685

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Reconciliation of differences between the statutory U.S. federal income tax rate and our effective tax rate follows for the years ended December 31:

(In thousands)	2008			%			2007			%			2006			%

Income tax provision (benefit) at federal statutory rate	$	(19,099	)		35.0		$	11,663			35.0		$	30,305			35.0
Increase/(decrease) in taxes resulting from:
State and local taxes, net of federal benefit		(1,994	)		3.7			947			2.8			3,314			3.8
FIN 48 recognition of previously unrecognized uncertain tax positions		-			-			(8,089	)		(24.3	)		-			-
Tax exempt interest income		-			-			(2,592	)		(7.8	)		(667	)		(0.8	)
Increase (decrease) in valuation allowances		16,142			(29.6	)		(1,563	)		(4.7	)		(2,023	)		(2.3	)
Deferred tax adjustments		(1,197	)		2.2			-			-			-			-
Indemnification proceeds		(1,185	)		2.2			-			-			-			-
Other		(139	)		0.2			(843	)		(2.4	)		756			0.9
Income tax expense/(benefit)	$	(7,472	)		13.7		$	(477	)		(1.4	)	$	31,685			36.6

Deferred income taxes included in our Consolidated Balance Sheets reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the carrying amount for income tax return purposes.

Significant components of our deferred tax assets and liabilities are as follows at December 31:

(In thousands)	2008			2007

Current deferred tax asset	$	1,593		$	853

Current deferred tax liability	$	507		$	379

Long-term deferred tax liabilities:
Basis of property, plant and equipment	$	5,389		$	3,858
Benefit obligations		15			-
Partnership investment		4,306			2,349
Long-term deferred tax liability	$	9,710		$	6,207

Long-term deferred tax assets:
Capital loss on securities	$	12,324		$	-
Investment in marketing alliances		3,377			1,419
Benefit obligations		-			241
Accumulated other comprehensive income		1,324			212
Other		531			1,952
Stock-based compensation		7,055			4,782
Long-term deferred tax assets		24,611			8,606
Valuation allowance		(17,345	)		(1,203	)
Net long-term deferred tax assets	$	7,266		$	7,403

Net long-term deferred tax asset (liability)	$	(2,444	)	$	1,196

The deferred tax provision for 2008, 2007 and 2006 does not reflect the tax effect of $(1.1) million, $0.5 million and $(0.1) million, respectively, resulting from the pension and other postretirement liability components included in accumulated other comprehensive income.

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At December 31, 2008 and 2007, the Company has recorded valuation allowance of $17.3 million and $1.2 million, respectively, on its deferred tax assets to reduce the deferred tax assets to the amount that management believes is more likely than not to be realized. Management considered the scheduled reversal of deferred tax liabilities and tax planning strategies in making this assessment. The deferred tax assets subject to the valuation allowance primarily include tax benefits associated with capital loss on securities, stock-based compensation, excess tax basis over corresponding book basis in marketing alliances and state income tax net operating loss carryforwards.

At December 31, 2008, we had deferred state tax benefits of $0.5 million relating to state net operating loss carryforwards, which are available to offset future state taxable income through 2029. Due to uncertainties regarding realization of the tax benefits, a valuation allowance of $0.5 million has been applied against the deferred state tax benefits at December 31, 2008.

At December 31, 2008, we had a capital loss carryforward of $12.3 million that is available to offset future consolidated capital gains. Due to uncertainties regarding the realization of the capital loss carryforward, a valuation allowance of $12.3 million has been applied against the deferred tax benefit at December 31, 2008.

We adopted the provisions of FIN 48 on January 1, 2007. As of December 31, 2008, the Company has unrecognized tax benefits of $0.9 million, none of which would impact the effective tax rate, if recognized. Unrecognized tax benefits are recorded in other long-term liabilities to conform to the balance sheet presentation requirements of FIN 48. We did not have any unrecognized tax benefits at December 31, 2007.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

Balance at January 1, 2008	$ -
Additions based on tax positions related to the current year	-
Reductions based on tax positions taken in previous years	-
Additions based on tax positions taken in previous years	874
Settlements	-
Reductions for lapse of statute of limitations	-
Balance at December 31, 2008	$874

We include the interest expense or income, as well as potential penalties on unrecognized tax benefits, as components of income tax expense in the condensed consolidated statement of operations. The total amount of accrued interest related to uncertain tax positions at December 31, 2008 was $26 thousand, net of the deferred tax benefit.

The Company files a federal and various state income tax returns. Our federal income tax returns for 2005 to 2007 are open tax years under statue of limitations. Our federal income tax returns for 2006 and 2007 are under examination. We file in numerous state and foreign jurisdictions with varying statues of limitations open from 2004 to 2008.

In December 2004, the FASB issued Staff Position No. FAS 109-1, Application of SFAS 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004 (FSP 109-1). The Company did not recognize any tax benefits related to the qualified domestic production credit for the year ended December 31, 2008. For the year ended December 31, 2007, the Company recognized $0.3 million in tax benefits related to the qualified domestic production credit.

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18. Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss, net of tax, at December 31, are as follows:

(In thousands)	Accumulated Other Comprehensive (Loss)
Balance at December 31, 2005		(867	)
Adjustment to initially apply SFAS 158, net of tax benefit of $109		(207	)
Balance at December 31, 2006		(1,074	)
Pension and postretirement liability adjustment, net of tax of $475		750
Balance at December 31, 2007		(324	)
Pension and postretirement liability adjustment, net of tax of $1,112		(1,746	)
Balance at December 31, 2008	$	(2,070	)

19. Stockholder Rights Plan

On December 12, 2005, the Board of Directors adopted a stockholder rights plan under which each common shareholder was issued one preferred share purchase right for each share of common stock outstanding prior to the 144a equity offering. In addition, each share of common stock issued in the offering or after the consummation of the offering will be issued with an accompanying preferred share purchase right. Each right will entitle the holder, under certain circumstances, to purchase one one-thousandth of a share of the Company’s Series A participating cumulative preferred stock, par value $0.001 per share, at an initial purchase price of $60.00 per one one-thousandth of a share of Series A participating cumulative preferred stock. The Company may exchange the rights at a ratio of one share of common stock for each right at any time after a person or group acquires beneficial ownership of 20% or more of its common stock but before such party acquires beneficial ownership of 50% or more of its common stock. The Company may also redeem the rights at its discretion at a price of $0.001 per right at any time before a person or party has acquired beneficial ownership of 20% or more of its common stock. The rights will expire on November 30, 2015, unless earlier exchanged or redeemed. Each share of Series A participating cumulative preferred stock that is purchased upon exercise of a right entitles the holder to receive an aggregate quarterly dividend payment of $1.00 or 1,000 times the cash and noncash dividends declared per share of common stock, whichever is greater. As of December 31, 2008, there were no Series A participating preferred stock rights that had been exercised.

20. Stock-Based Compensation Plans

As of December 31, 2008, we maintained one stock-based compensation plan, the Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan (the “Plan”). Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004) (“SFAS 123(R)”), Share-Based Payment utilizing the modified prospective transition method. SFAS 123(R) requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including stock options and non-vested stock, based on their fair values at the time of grant.

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The Plan was adopted by the Board of Directors (the “Board”) effective May 30, 2003, and was amended on each of September 6, 2005, December 12, 2005, March 22, 2007 and April 16, 2007. The Plan provides for the grant of awards in the form of stock options, restricted shares or units, stock appreciation rights and other equity-based awards to directors, officers, employees and consultants at the discretion of the Board or the Compensation Committee of the Board. The term of awards granted under the plan is determined by the Board or by the Compensation Committee of the Board, and cannot exceed ten years from the date of grant. The maximum number of shares of common stock that may be issued under the Plan is limited to 6,701,172, provided that no more than 750,000 shares may be granted in the form of stock options or stock appreciation rights to any “covered employee” (as defined under Section 162(m) of the Internal Revenue Code) in any calendar year. Unless terminated sooner, the Plan will continue in effect until May 29, 2013.

Upon adoption of SFAS 123(R), the Company elected to value its share-based payment awards granted beginning in fiscal year 2006 using a form of the Black-Scholes option-pricing model (the “Option Pricing Model”). The Option Pricing Model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. 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 had 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 2008 were estimated using a 3% forfeiture rate. During 2008, we adjusted the forfeiture rate to 6.4% 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.

Beginning in 2007, the Company commenced an ongoing long-term incentive program under the Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan, as amended (the “Plan”). It is anticipated that this program will provide regular annual grants of performance shares. Performance shares are stock units that will be converted to common shares, to the extent earned, at the end of a three-year performance cycle. Under the performance share program, each participant is given a target award expressed as a number of shares, with a payout opportunity ranging from 0% to 150% of the target, depending on the performance relative to pre-determined goals. Under FAS 123(R), an accounting estimate of the number of these shares that are expected to vest is made and these shares are then expensed utilizing the grant-date fair value of the shares from the date of grant through the end of the performance cycle period.

The first performance cycle began on January 1, 2007, and ends on December 31, 2009. The performance goals for the January 1, 2007 to December 31, 2009 performance cycle relate to the growth of the Company as measured by actual equity gallons produced. On May 25, 2007, the Company issued 94,500 performance shares at the target award level to various participants under the Plan. In 2008, we determined that we did not expect to meet the minimum performance criteria relative to the pre-determined goals for the January 1, 2007 to December 31, 2009 performance cycle, as we would not achieve the requisite minimum production of equity gallons to qualify for a payout. As a result, all of the expense totaling $0.8 million previously recorded relative to this performance measurement was reversed in 2008. No expense relative to this performance cycle will be recorded in 2009.

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Under the performance share program, a second performance cycle was established whose performance criteria relates to the relative performance between the Company and VeraSun Energy Corporation using the metric of EBITDA (as defined) divided by produced denatured gallons of ethanol. This second performance cycle runs from the fourth quarter of 2007 until the third quarter of 2010. The performance measurement is compared against a base year defined as the fourth quarter of 2006 through the third quarter of 2007. On February 21, 2008, the Company issued 106,500 performance shares at the target award level to various participants under the Plan. In 2008, we determined that we did not expect to meet the minimum performance criteria relative to the pre-determined goals for this performance cycle. As a result, we did not record any expense in 2008. No expense relative to this performance cycle will be recorded in 2009.

Pre-tax stock-based compensation expense for the year ended December 31, 2008 was approximately $5.7 million, of which $0.1 million was charged to cost of goods sold and $5.6 million was charged to selling, general and administrative expense. This expense reduced earnings per share by $0.08 per basic share and $0.08 per diluted share for the year ended December 31, 2008. Pre-tax stock-based compensation expense for the year ended December 31, 2007 was approximately $7.2 million, of which $0.2 million was charged to cost of goods sold and $7.0 million was charged to selling, general and administrative expense. This expense reduced earnings per share by $0.11 per basic share and $0.10 per diluted share for the year ended December 31, 2007. The Company recognized a tax benefit on its consolidated statement of income from stock-based compensation expense in the amount of $1.7 million and $2.8 million, respectively, for the 12 month periods ended December 31, 2008 and 2007. The Company recorded pre-tax stock-based compensation expense for the year ended December 31, 2008, 2007 and 2006 as follows:

	Year Ended December 31,
(in millions)	2008			2007		2006

Stock-based compensation expense:
Non-qualified options	$	5.5		$	6.5	$	6.4
Restricted stock	$	0.3		$	0.2	$	0.1
Restricted stock units	$	0.3		$	0.1	$	-
Long-term incentive plan	$	(0.4	)	$	0.4	$	-

As of December 31, 2008, the Company had not yet recognized compensation expense on the following non-vested awards:

(in millions)	Non-recognized Compensation		Average Remaining Recognition Period (years)

Non-qualified options	$	11.6		2.3
Restricted stock		0.7		0.9
Restricted stock units		0.2		0.3
Long-term incentive plan		-		-
Total	$	12.5		2.2

The determination of the fair value of the stock option awards, using the Option Pricing Model for the years ended December 31, 2008, 2007 and 2006, incorporated the assumptions in the following table for stock options granted:

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	December 31,
	2008		2007		2006

Expected stock price volatility		58%		58%		58%
Expected life (in years)		6.5		6.5		6.5
Risk-free interest rate		4.52%		4.76%		4.92%
Expected dividend yield		0%		0%		0%
Weighted average fair value	$	4.16	$	9.76	$	14.52

The following table summarizes stock options outstanding and changes during the years ended December 31, 2008, 2007 and 2006:

	Shares (in thousands)			Weighted- Average Exercise Price		Weighted- Average Remaining Life (years)		Aggregate Intrinsic Value (in thousands)
Options outstanding – December 31, 2005		2,919		$	2.01
Granted		670			23.70
Exercised		(269	)		0.82
Cancelled or expired		(55	)		0.23
Options outstanding – December 31, 2006		3,265		$	6.57
Granted		480			16.00
Exercised		(201	)		2.54
Cancelled or expired		(28	)		4.35
Options outstanding – December 31, 2007		3,516		$	8.10		7.4	$	7,911
Options exercisable – December 31, 2007		1,234		$	3.77		6.5	$	8,120
Granted		568		$	6.85
Exercised		-			-
Cancelled or expired		(190	)	$	14.31
Options outstanding – December 31, 2008		3,894		$	7.62		6.7	$	422
Options exercisable – December 31, 2008		2,059		$	4.83		5.7	$	405

The range of exercise prices of the exercisable options and outstanding options at December 31, 2008 are as follows:

Weighted-Average Exercise Price	Number of Exercisable Options (in thousands)		Number of Outstanding Options (in thousands)		Weighted- Average Remaining Life (years)
$0.23		992		1,006		4.5
$2.36 - $4.80		734		1,410		6.7
$7.05		-		478		9.2
$15.26 - $17.29		66		330		8.3
$22.15 - $22.50		252		630		7.3
$43.00		16		40		7.5
Totals		2,059		3,894		6.7

In anticipation of our initial public offering, on June 6, 2006, our Board gave contingent approval of the acceleration of vesting of 71,488 options held by officers and employees to be effective immediately prior to the consummation of the initial public offering. The Board approved the acceleration of the vesting in order to permit certain members of management the ability to sell stock in our initial public offering.

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These options had a weighted-average exercise price of $4.35 per share. As a result of the accelerated vesting, we recorded a pre-tax charge to earnings of $0.6 million in 2006.

In 2007, we awarded 70,531 shares of restricted stock under the Plan, with a weighted-average fair value at the date of grant of $15.40 per share. These restricted shares vest 20% per year annually at the anniversary date of the grant. We recorded compensation expense with respect to restricted stock awards of approximately $0.2 million in 2007 which is recognized on a straight-line basis over the five year vesting period of the restricted stock grants. In 2006, we awarded 8,060 shares of restricted stock under the Plan, with a weighted-average fair value at the date of grant of $27.92 per share. These restricted shares vest 33% per year annually at the anniversary date of the grant. We recorded compensation expense with respect to restricted stock awards of approximately $0.1 million in 2006 which is recognized on a straight-line basis over the three year vesting period of the restricted stock grants.

Restricted stock award activity for the years ended December 31, 2008, 2007 and 2006 is summarized below.

	Shares (in thousands)			Weighted- Average Grant Date Fair Value per Award
Unvested restriced stock awards at January 1, 2006		-			-
Granted		8.1		$	27.92
Vested		-			-
Cancelled or expired		-			-
Unvested restricted stock awards – December 31, 2006		8.1		$	27.92
Granted		70.5			15.40
Vested		(2.7	)		27.93
Cancelled or expired		-			-
Unvested restricted stock awards – December 31, 2007		75.9		$	16.69
Granted		-			-
Vested		(16.8	)		17.41
Cancelled or expired		-			-
Unvested restricted stock awards – December 31, 2008		59.1		$	15.97

Restricted stock units represent the right to receive a share of stock in the future, provided that the restrictions and conditions designated have been satisfied. There were no restricted stock unit awards made by the Company prior to 2007. Restricted stock unit award activity for the years ended December 31, 2008 and 2007 is summarized below:

	Shares (in thousands)			Weighted Average Grant Date Fair Value per Award

Unvested Restricted stock unit awards – January 1, 2007		-		$	-
Granted		18.0		$	15.85
Vested		-			-
Cancelled or expired		-			-
Unvested restricted stock unit awards – December 31, 2007		18.0		$	15.85
Granted		46.5		$	6.88
Vested		(18.0	)	$	15.85
Cancelled or expired		-			-
Unvested restricted stock unit awards – December 31, 2008		46.5		$	6.88

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21. Commitments

We lease certain assets such as rail cars, terminal facilities, barges, buildings and equipment from unaffiliated parties under non-cancelable operating leases. Terms of the leases, including renewals, vary by lease. Minimum future rental commitments under our operating leases having non-cancelable lease terms in excess of one year totaled approximately $177.8 million as of December 31, 2008 and are payable as follows:

(in millions)
2009	$33.7
2010	$25.7
2011	$22.4
2012	$19.4
2013	$17.8
Thereafter	$58.9

Rental expense for operating leases was $38.3 million in 2008, $25.4 million in 2007, and $17.7 million in 2006.

At December 31, 2008, we have remaining commitments of $47.7 million for the construction of two new dry mill facilities in Aurora, Nebraska and Mt. Vernon, Indiana, excluding the $27.4 million construction obligation included in accounts payable. We had no other commitments for capital expenditures at December 31, 2008. 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 $24.4 million at February 28, 2009 are due and payable.

We are party to ethanol marketing alliance contracts which require us to purchase and market all ethanol produced from these alliance ethanol facilities. Under these contracts, the Company is generally obligated to purchase all of the ethanol produced by these facilities at a purchase price that is based upon the price at which it sells the ethanol less a pre-negotiated margin. As described in Note 24, the Company negotiated termination of nearly all of these contracts subsequent to year-end.

At December 31, 2008, we have committed to purchase approximately 484,800 MMBtus of natural gas at a weighted average fixed price of $9.98 during 2009.

At December 31, 2008, we had futures contracts to purchase approximately 245,000 tons of coal at a weighted average fixed price of $73.48 per ton.

At December 31, 2008, we also had commitments to purchase approximately 6.3 million bushels of corn through December 2009, at an average price of $5.60 per bushel. These commitments were negotiated in the normal course of business and represent a portion of our corn requirements, which we anticipate will exceed 76 million bushels in 2008.

We have contractual obligations, subject to certain conditions, to build a second 113 million gallon expansion in Mount Vernon, Indiana. If we do not meet certain specified milestones or decide not to pursue the expansions, we could be subject to material penalties.

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22. Earnings Per Share

The following table sets forth the computation of earnings per share for the years ended December 31:

	2008			2007		2006
(In thousands, except per share amounts)

Income (loss) available to common shares	$	(47,096	)	$	33,799	$	54,901

Basic weighted-average common shares		42,136			41,886		38,411
Dilutive stock options (1)		-			465		1,228
Diluted weighted-average common and common equivalent shares		42,136			42,351		39,639

Earnings (loss) per common share—basic:	$	(1.12	)	$	0.81	$	1.43
Earnings (loss) per common share—diluted:	$	(1.12	)	$	0.80	$	1.39

(1) To the extent that stock options are anti-dilutive, they are excluded from the calculation of diluted earnings/(loss) per share in accordance with SFAS 128.

We had additional potential dilutive securities outstanding representing 3.9 million and 1.2 million common shares, respectively, for the years ended December 31, 2008 and 2007 that were not included in the computation of potentially dilutive securities because the options’ exercise prices were greater than the average market price of the common shares or they were anti-dilutive. For the year ended December 31, 2006, we had 40,000 common shares that were not included in the computation of potentially dilutive securities because the options’ exercise price were greater than the average market price of the common shares.

23. Quarterly Results of Operations (Unaudited)

The following is a summary of the unaudited quarterly results of operations for the years ended December 31, 2008 and 2007:

2008	March 31			June 30			September 30			December 31
(In thousands, except per share amounts)
Net sales	$	509,948		$	601,591		$	599,520		$	537,242
Gross profit (loss)	$	24,083		$	32,860		$	(6,470	)	$	(41,512	)
Net income (loss)	$	(10,795	)	$	(1,918	)	$	2,486		$	(36,869	)

Basic earnings (loss) per common share:	$	(0.26	)	$	(0.05	)	$	0.06		$	(0.86	)
Diluted earnings (loss) per common share:	$	(0.26	)	$	(0.05	)	$	0.06		$	(0.86	)

2007
(In thousands, except per share amounts)
Net sales	$	436,662		$	394,914		$	360,674		$	379,357
Gross profit (loss)	$	28,415		$	27,429		$	(1,727	)	$	19,683
Net income	$	14,940		$	12,607		$	2,995		$	3,257

Basic earnings per common share:	$	0.36		$	0.30		$	0.07		$	0.08
Diluted earnings per common share:	$	0.35		$	0.30		$	0.07		$	0.08

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24. Subsequent Events

Because the Company’s obligations to Kiewit are past due, the liens securing these obligations violate the terms of its 10% fixed rate notes and constitute a default thereunder. Unless such default is cured through payment, the release of the liens, a negotiated resolution or otherwise, the holders of the 10% fixed rate notes may accelerate the $300 million principal amount thereof upon 60 days notice. In addition, the default under the 10% fixed rate notes constitutes an event of default under the Company’s secured revolving credit facility, which has been waived by the lenders thereunder until April 15, 2009. See Notes 10 and 11.

On March 10, 2009, the Company amended its secured revolving credit facility. See Note 10.

Due to severely declining margins and general liquidity stress due to frozen credit markets, the Company is significantly reducing the number of gallons it sources from third parties. Beginning in the fourth quarter of 2008 the Company began negotiating termination agreements with most of its marketing alliance partners and subsequent to year-end has negotiated termination of nearly all of them. The Company received termination settlements of $14.1 million. The Company has also undertaken a strategy to rationalize its distribution and logistics system to focus primarily on its equity production. This rationalization process is expected to entail significantly reducing or eliminating the Company’s presence in numerous terminals, the amount of ethanol transported via barge, and the number of railcars the Company uses to distribute ethanol. In connection with the rationalization, the Company has subleased or assigned the majority of its railcar, barge and terminal leases. On sublease arrangements, the Company remains secondarily liable to the lessor.

In January 2009, the Company sold its interests in Ace Ethanol, LLC and Granite Falls Energy LLC, recording gains totaling $1.0 million.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Aventine Renewable Energy Holdings, Inc.

We have audited the accompanying consolidated balance sheets of Aventine Renewable Energy Holdings, Inc. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Aventine Renewable Energy Holdings, Inc. and subsidiaries at December 31, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

The accompanying financial statements have been prepared assuming that Aventine Renewable Energy Holdings, Inc. will continue as a going concern. As more fully described in Note 1, the Company has incurred substantial losses from operations and has experienced a significant reduction in available liquidity in recent quarters. In addition, the Company is dependent on its revolving credit facility, described in Note 10, to fund its working capital needs. The availability of funds under the revolving credit facility is dependent upon the Company maintaining certain collateral levels and maintenance cannot be assured. Further, as described in Note 11, the Company is in default of its debt covenants on the senior unsecured fixed rate notes. Payment of these notes may be accelerated unless the default is cured and such cure cannot be assured. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters also are described in Note 1. The 2008 financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Aventine Renewable Energy Holdings, Inc.'s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 13, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

St. Louis, Missouri

March 13, 2009

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

We have audited Aventine Renewable Energy Holdings, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Aventine Renewable Energy Holdings, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Aventine Renewable Energy Holdings, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Aventine Renewable Energy Holdings, Inc. as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008 of Aventine Renewable Energy Holdings, Inc. and our report dated March 13, 2009 expressed an unqualified opinion thereon that included an explanatory paragraph regarding Aventine Renewable Energy Holdings, Inc.’s ability to continue as a going concern.

/s/ Ernst & Young LLP

St. Louis, Missouri

March 13, 2009

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Schedule II—Valuation and Qualifying Accounts

Description	Balance Beginning of Period	Charged to Cost and Expenses	Charged to Other Accounts	Deductions	Balance at End of Period
(In thousands)
Year ended December 31, 2008
Deducted from assets accounts:
Deferred tax valuation	$1,203	$16,122	$ -	$ -	$17,325
Year ended December 31, 2007:
Deducted from assets accounts:
Deferred tax valuation	$3,537	$2,334	$ -	$ -	$1,203
Year ended December 31, 2006:
Deducted from assets accounts:
Deferred tax valuation	$5,703	$2,166	$ -	$ -	$3,537

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Exhibit Index

Exhibit No.	Description

10.1.4	Fourth Amendment to Mt. Vernon Lease Agreement, dated as of June 19, 2008

10.1.5	Fifth Amendment to Mt. Vernon Lease Agreement, dated as of December 18, 2008

10.1.6	Sixth Amendment to Mt. Vernon Lease Agreement, dated as of February 12, 2009

10.5.1	Amendment to Engineering, Procurement and Construction Services Fixed Price Contract, dated as of October 1, 2008, between Aventine Renewable Energy – Aurora West, LLC and Kiewit Energy Company

10.5.2	Change Order Number 123108AW to Engineering, Procurement and Construction Services Fixed Price Contract, dated December 31, 2008, between Aventine Renewable Energy – Aurora West, LLC and Kiewit Energy Company

10.5.3	Aurora West EPC Termination Letter from Kiewit Energy Company dated as of March 6, 2009

10.6.1	Change Order Number 123108MV to Engineering, Procurement and Construction Services Fixed Price Contract, dated December 31, 2008, between Aventine Renewable Energy – Mt. Vernon, LLC and Kiewit Energy Company

10.6.2	Mt. Vernon EPC Termination Letter from Kiewit Energy Company dated as of March 6, 2009

10.15.1	First amendment to Credit Agreement, dated as of March 10, 2009, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent.

10.15.2	Letter agreement dated March 12, 2009, related to the Credit Agreement, dated as of March 23, 2007, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent.

21.1	List of subsidiaries of the Registrant

23.1	Consent of Independent Registered Public Accounting Firm

31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.