10-K 1 a2183205z10-k.htm 10-K
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

ý   Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for the fiscal year ended December 31, 2007

OR

o

 

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

Commission file number 001-32922

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

Delaware
(State of Incorporation or organization)
  05-0569368
(IRS Employer Identification No.)

120 North Parkway
Pekin, Illinois
(Address of principal executive offices)

 

61554
(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 whether the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES o NO ý

         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 o NO ý

         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 ý NO o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. ý

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

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

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

         The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 29, 2007 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 February 29, 2008
Common Stock, $0.001 par value   41,971,330 Shares

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the definitive proxy statement for the annual meeting of stockholders to be held on May 2, 2008 are incorporated by reference into Part III.





FORM 10-K
YEAR ENDED DECEMBER 31, 2007
TABLE OF CONTENTS

 
   
Page No.

PART I
Item 1.   Business 3
Item 1A.   Risk Factors 22
Item 1B.   Unresolved Staff Comments 36
Item 2.   Properties 37
Item 3.   Legal Proceedings 38
Item 4.   Submission of Matters to a Vote of Security Holders 38

PART II

Item 5.

 

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

39
Item 6.   Selected Financial Data 42
Item 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations 44
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


PART I

Item 1.    Business

General

        Aventine Renewable Energy Holdings, Inc. (the "Company," "Aventine," "we," "our," or "us") is a leading producer and marketer of ethanol in the United States ("U.S."), based on both the number of gallons produced and the number of gallons sold. Through our own production facilities, marketing alliances with other ethanol producers and our purchase/resale operations, we marketed and distributed 690.2 million gallons of ethanol in 2007 and 695.8 million gallons of ethanol in 2006. For the years ended December 31, 2007 and 2006, we sold approximately 10% and 13%, 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. We have comprehensive national distribution capabilities through our leased railcar and barge fleet and terminal network structure at critical points on the nation's transportation grid where our ethanol is blended with our customers' gasoline. We are also a marketer of bio-diesel. In addition to producing ethanol, our facilities also produce several co-products, such as distillers grain, corn gluten feed, corn germ and brewers' yeast, which generate incremental revenue and allow us to help offset a significant portion of our corn costs.

        We were acquired by the Morgan Stanley Capital Partners funds ("MSCP") from a subsidiary of The Williams Companies, Inc. on May 30, 2003. The acquisition was accounted for as a purchase business combination in accordance with 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.

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

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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 May 29, 2007. 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. Ethanol is generally priced using one of three methodologies: a negotiated fixed price, a price based upon the spot market price of ethanol at the time of shipment plus or minus a fixed amount, or a price based upon the price of wholesale gasoline plus or minus a fixed amount.

        The principal factors historically affecting the price of ethanol are:

    The price of gasoline.  Because ethanol is sold in both discretionary markets as well as in markets where reformulated gasoline ("RFG") is required in order to meet federal and state fuel emission standards, and is used as both an additive to, and as a substitute for, gasoline, the price of ethanol over the long term has historically moved in relation to the price of gasoline, which closely follows the price of oil;

    Federal ethanol tax incentives.  The Volumetric Ethanol Excise Tax Credit ("VEETC") enables refiners and blenders to be able to pay a premium for ethanol relative to the price of gasoline. As a result, ethanol had historically been priced near the cost of wholesale gasoline plus the value of the VEETC. However, the price of ethanol is highly influenced by the supply/demand balance of ethanol (see below). For most of 2007, ethanol traded at a price that was at or below the cost of wholesale gasoline; and

    Ethanol industry fundamentals (i.e. supply and demand).  The ethanol industry has experienced explosive growth in recent years, both in terms of supply capacity and demand. In periods when supply has exceeded demand, the price of ethanol has tended to fall below the cost of wholesale gasoline plus the value of the VEETC. In periods when demand outpaced supply, the price of ethanol tended to be at or above the cost of wholesale gasoline plus the value of the VEETC. See "Item 1A—Risk Factors—We operate in a highly competitive industry with low barriers to entry. In addition, if the expected increase in ethanol demand does not occur, of if the demand for ethanol otherwise decreases, there may be excess capacity in our industry."

        According to recent industry reports, approximately 99% of domestic ethanol is produced from corn fermentation as of December 31, 2007 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 1.3 billion gallons of production in 1997 to approximately 6.5 billion gallons produced in 2007, with year-end 2007 production capacity of 7.5 billion gallons annually. Ethanol blends accounted for approximately 4.8% of the U.S. gasoline supply in 2007. Increases in ethanol demand have 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

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      Independence and Security Act of 2007 signed into law on December 19, 2007, increased the mandated minimum use of renewable fuels to 9 billion gallons in 2008 (up from a 5.4 billion gallon requirement, which was the previous mandated 2008 requirement under the Energy Policy Act of 2005). The mandated usage of renewable fuels increases to 36 billion gallons in 2022. The upper mandate for corn based ethanol is 15 billion gallons by 2015.

    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 RFG 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 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 28% from 1980 to 2006, domestic gasoline consumption has increased 40% 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, 2007, only 1,441 gasoline stations across the U.S. sold E85), and by the number of automobiles capable of using the fuel (approximately 6 million at December 31, 2007). 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.

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. A typical wet mill yields approximately 2.6 gallons of fully denatured ethanol per bushel of corn, while a typical dry mill yields approximately 2.8 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

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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, at 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 is the minimum allowed by law.

        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, 2007, 2006 and 2005, we recovered 46.3%, 51.1% and 61.5%, 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 a 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, 2007, 2006 and 2005, we recovered 26.6%, 27.7% and 36.7%, 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:

GRAPHIC

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Business Overview

        We derive our revenue from the sale of biofuels, including ethanol and bio-diesel. 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 sources:

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

    Ethanol we purchase from marketing alliance partners, which we refer to as marketing alliance production; and

    Ethanol we purchase on the spot market, which we refer to as purchase/resale.

        We market and sell ethanol without regard to whether we produced it, are reselling it, or are marketing it for our marketing alliance partners. Through our own production facilities, marketing alliances with other ethanol producers and our purchase/resale operations, we marketed and distributed 690.2 million, 695.8 million, and 529.8 million gallons of ethanol for the years 2007, 2006 and 2005, respectively.

        In 2007, we began to market bio-diesel which we purchase from third-party producers. In 2007, we marketed and distributed 7 million gallons of bio-diesel. We expect our bio-diesel marketing business to increase significantly in terms of both the number of gallons transacted and the revenue dollars generated from bio-diesel sales. Although for the foreseeable future, we do not expect bio-diesel to be a meaningful contributor to net income.

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 also hold a 78.4% interest in a natural gas-fired corn dry mill plant in Aurora, Nebraska, which we refer to as the "Nebraska facility." The remaining 21.6% of the Nebraska facility is owned by Nebraska Energy Cooperative, an agricultural cooperative comprised of 220 corn producers. We consolidate all of the assets, liabilities, revenue, expenses and cash flows of the Nebraska facility in our financial statements and the interest therein of the Nebraska Energy Cooperative is reflected as minority interest. The 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 beginning in January 2007.

        At December 31, 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. At December 31, 2006, our facilities 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 89% of capacity during the fourth quarter of 2007 and 93% for the full year as compared to 89% for the full year 2006.

        For the years ended December 31, 2007, 2006 and 2005, we produced 192.0 million, 133.0 million and 138.1 million gallons of ethanol, respectively, from our own facilities. Our equity production operations generate the substantial majority of our operating income.

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Marketing Alliance Production

        We also source ethanol from marketing alliance partners. Our marketing alliance partners are third-party producers (including producers in which we may have a minority interest, each of which is less than 8%), which 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. Our 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, 2007, 2006 and 2005, we purchased 395.0 million, 493.0 million and 340.6 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.

        At December 31, 2007, the annual run-rate of operating marketing alliance plants was 504 million gallons annually. We have also signed marketing alliance contracts with both existing and new alliance partners totaling an additional 1.5 billion gallons of ethanol production annually. Of this amount, 416 million gallons is currently under construction and 1.1 billion gallons is under development but not yet under construction. There can be no assurances that any or all of the projects under construction will be completed on a timely basis or at all and, given current industry and financial market conditions, it is uncertain whether any or all of the plants not yet under construction will be commenced or completed as scheduled or at all. We expect revenue and marketing alliance production to significantly increase in 2008 as those marketing alliance partner plants currently under construction come online.

Purchase/Resale

        We also purchase ethanol from third-party producers and marketers. 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, 2007, 2006 and 2005, we purchased for resale 111.5 million, 68.2 million and 68.8 million gallons of ethanol, respectively, from third-party producers and marketers. Although we expect this program to grow both in the number of gallons transacted and in revenue dollars, our expectations are that the contribution to our operating income from purchase/resale transactions will continue to be limited for the foreseeable future.

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Bio-diesel

        Beginning in 2007, we began to market bio-diesel under a program similar in nature to our purchase/resale program for ethanol. We purchase bio-diesel from third-party producers and marketers. These transactions are driven by our ability to purchase bio-diesel and then, through our distribution network and customer relationships, resell the bio-diesel. The margin from these transactions can be volatile and we can occasionally incur losses on these transactions. Although revenue from this type of transaction is small, we expect this program to grow both in the number of gallons transacted and in revenue dollars, although for the foreseeable future we do not expect bio-diesel to be a meaningful positive contributor to net income.

        For the year ended December 31, 2007, we purchased for resale 7 million gallons of bio-diesel from third-party producers and marketers.

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, 2007, 2006 and 2005, we generated approximately $99.3 million, $54.7 million and $60.3 million, respectively, of revenue from the sale of co-products and bio-products, allowing us to recapture approximately 36.7%, 44.7%, and 55.9% of our corn costs, respectively, in each of these years. Co-product returns, as a percentage of corn costs, declined in 2007 as a result of the addition of our new 57 million gallon dry mill in Pekin, Illinois. 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 our new Pekin dry mill, the overall product mix between wet and dry co-products produced changed from 66% higher value wet mill products and 33% lower value dry mill product in previous years to roughly 50% higher value wet mill products and 50% lower value dry mill product in 2007.

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

Products

Ethanol

        Our principal product is fuel-grade ethanol, an alcohol which is derived in the U.S. principally from corn. Ethanol is sold primarily for blending with gasoline as an octane enhancer, as an oxygenate additive for the purpose of meeting fuel emission standards and as a fuel extender. The demand for ethanol has historically been principally driven by the overall demand for gasoline. However, recent demand for ethanol has been driven primarily by the elimination of MTBE as a blend component and from the requirements of a renewable fuel standard beginning in 2005. For the years ended

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December 31, 2007, 2006 and 2005, ethanol sales represented 91.3%, 95.4% and 92.4%, 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, 2007, 2006 and 2005, co-products represented 5.7%, 2.9% and 5.3%, 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, 2007, 2006 and 2005, bio-products represented 0.6%, 0.6% and 1.1%, respectively, of our total revenue.

Competition

        As of December 2007, there were 91 producers operating 136 ethanol plants in the U.S. The top ten producers accounted for approximately 54.3%, 44.4% and 46.3% of total industry capacity for the years 2007, 2006 and 2005, respectively. The remaining producers consist primarily of farmer cooperatives. We expect recent consolidation activity in the industry to continue.

        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 2007, imports of ethanol into the U.S. were not significant to the U.S. domestic marketplace. In the past, there have been occasions of significant imports of ethanol into the U.S. having 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 and Growth Strategy

        We are pursuing the following business and growth strategies:

Add Production Capacity to Meet Expected Demand for Ethanol

        We have identified opportunities to increase our equity production capacity through the development of new production facilities and are continually exploring acquisition opportunities. We are currently building 113 million gallon annualized capacity ethanol production facilities at both Mt. Vernon, Indiana and Aurora, Nebraska, which we expect to begin ramping up ethanol production in the first quarter of 2009. In addition, we are obligated to add an additional 113 million gallons of capacity through a phase II expansion in Mt. Vernon, Indiana, and would be subject to material penalties if we do not. We also intend to add an additional 113 million gallons of capacity through a phase II expansion at Aurora, Nebraska, along with potentially expanding our existing Pekin, Illinois campus. The timing of these expansions will be based upon, among other factors, market conditions and the availability of financing on attractive terms. We anticipate that the aggregate capital expenditures to build our phase I expansion at each of Mt. Vernon and Aurora will be approximately $250 million per plant, which includes approximately $15 million of additional infrastructure at each plant to facilitate the construction of the phase II expansion. We have not yet entered into agreements for any of our additional expansions. The cost to build these additional expansions will depend on market conditions at the time construction is commenced and may be higher or lower than the cost of the phase I expansions at Mt. Vernon and Aurora. There can be no assurance that we can raise additional funds to complete these projects.

        We may be subject to material penalties if we do not timely complete phase I of the Aurora Expansion or either phase 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. If we 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 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 March 1, 2009 and substantial completion of phase II (an additional 110 million gallons of capacity) by January 1, 2011, subject in the case of the 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 alternations, (ii) without terminating the lease, require us 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. In addition, under the design build agreements for the initial 113 million gallon capacity expansion at each of Mt Vernon and Aurora, we have the ability to delay construction by up to 180 days. If we do so, we will be responsible for certain increased costs and foregone profit of the contractor (potentially including an early completion bonus). If we were to delay construction beyond 180 days the contractor would be entitled

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to treat the delay as a termination by us for convenience and we would be responsible for certain costs and expenses of the contractor in connection with such termination as well as a termination fee of 1% of the total EPC contract sum.

Expand Marketing Alliances

        We signed our first marketing alliance agreement in 2001 and as of December 31, 2007 have increased the program to thirteen alliance contracts with operating third-party plants. As of December 31, 2007, these thirteen alliance partners have operations whose current production capacities total approximately 504 million gallons of ethanol annually.

Capitalize on Current and Changing Regulation

        Through expansion of marketing alliances and continued investment in increasing production capacity, we believe we are well positioned to take advantage of the current and changing regulatory environment in our industry. For example, the Energy Independence and Security Act of 2007 increased the mandated minimum use of renewable fuels to 9 billion gallons in 2008 (up from a 5.4 billion gallon requirement, which was the previous mandated 2008 requirement under the Energy Policy Act of 2005). The mandated usage of renewable fuels increases to 36 billion gallons in 2022. The upper mandate for corn based ethanol is 15 billion gallons by 2015.

Research into Cellulosic Ethanol

        Cellulosic plant biomass represents an untapped potential feedstock for the generation of fuel ethanol from renewable resources. We are working to develop an efficient and economical pretreatment process for corn fiber and corn stover (the stalks and husks left over after harvest). We spent approximately $0.3 million, $0.2 million and $0.1 million on cellulosic research in 2007, 2006, and 2005, respectively. We maintain our commitment to continue our research of the potential benefits associated with cellulosic ethanol.

Entry into new and diversified markets.

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

Sales and Marketing

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

Marketing Alliances

        We believe we have one of the largest marketing alliance networks in the ethanol industry, which allows for increased sales and enhances our position as a leading player in the ethanol industry. In exchange for allowing us to market their ethanol exclusively, marketing alliance partners gain the benefit of our customer relationships and extensive distribution network. Under our marketing alliance contracts, we agree to purchase all fuel-grade ethanol produced by our marketing alliance partners. The purchase price we pay our marketing alliance partners is based on an average price at which we sell

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ethanol less a cost recovery component and commission. The cost recovery component represents reimbursement to us for certain costs, including freight, storage, inventory carrying cost and indirect marketing costs. In addition, our marketing alliance partners pay us a commission which is generally 1% or less of the netback price. The netback price is the selling price of ethanol less the cost recovery component. Our marketing alliance contracts typically have two year terms and renew automatically for additional one year terms unless either party elects to terminate in advance. During the years ended December 31, 2007, 2006 and 2005, we purchased 395.0 million, 493.0 million and 340.6 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.

        We signed our first marketing alliance agreement in 2001 and as of December 31, 2007 have increased the program to thirteen alliance contracts with operating third-party plants. As of December 31, 2007, these thirteen alliance partners have operations whose current production capacities total 504 million gallons of ethanol annually. In addition, as of December 31, 2007, we have signed additional marketing alliance contracts with both existing and new alliance partners that have either announced new ethanol production facilities or have facilities currently under construction which would represent an additional 1.5 billion gallons of ethanol per year if fully completed. There can be no assurances that any or all of the projects under construction will be completed on a timely basis or at all and, given current industry and financial market conditions, it is uncertain whether any or all of the plants not yet under construction will be commenced or completed as scheduled or at all.

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        The following table presents our marketing alliances as of December 31, 2007:

Name

  Location
  Annual Capacity
(millions of gallons)

Existing Marketing Alliance Plants
Ace Ethanol, LLC *   Stanley, WI   41
Adkins Energy   Lena, IL   40
Advanced BioEnergy, LLC * (1)   Huron, SD   30
Advanced BioEnergy, LLC *   Aberdeen, SD   9
Agri Energy, LLC   LuVerne, MN   21
E Energy Adams   Adams, NE   50
Glacial Lakes Energy   Watertown, SD   100
Granite Falls Energy, LLC *   Granite Falls, MN   52
Husker Ag, LLC   Plainview, NE   67
Quad County Corn Processors (2)   Galva, IA   27
Redfield Energy, LLC   Redfield, SD   50
Reeve Agri-Energy   Garden City, KS   12
Xethanol Biofuels   Blairstown, IA   5
       
        504
       

Marketing Alliance Plants Financed and Under Construction
Aberdeen Energy, LLC   Aberdeen, SD   100
Ethanol Grain Processors   Obion, TN   100
Indiana Bio-Energy, LLC *   Bluffton, IN   101
Panda Energy   Hereford, TX   115
       
        416
       

Marketing Alliance Plants Announced But Not Commenced
Alabama Renewable Energy   Dadeville, AL   55
Dawson County Ethanol   Elm Creek, NE   100
E Energy Auburn   Auburn, NE   100
E Energy Broken Bow   Broken Bow, NE   100
Furnas County Ethanol   Arapahoe, NE   100
Holt County Ethanol   Holt County, NE   100
Illinois Bio-Energy   Hartsburg, IL   100
Monona County Ethanol   Blencoe, IA   100
Phelps County Ethanol   Holdridge, NE   100
Panda Ethanol, Inc.    Yuma, CO   115
Panda Ethanol, Inc.    Haskell County, KS   115
Yellowstone Ethanol   Williston, ND   50
       
        1,135
       

Total Marketing Alliances

 

2,055

*
Denotes marketing alliance partners in which we have made equity investments.

(1)
Advanced BioEnergy, LLC, which produces 39 million gallons of ethanol annually, has notified us in writing that they intend to leave our marketing alliance on December 1, 2008. We are currently in discussions with Advanced BioEnergy on a new marketing alliance contract.

(2)
On July 20, 2007, Quad County Corn Processors ("QCCP") notified us in writing that they intended to leave our marketing alliance on January 20, 2008. On January 21, 2008, we signed an

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    agreement with QCCP whereby we contracted to purchase their production of ethanol, and sell it at prevailing prices outside of our existing marketing alliance pool.

        We have made investments in four marketing alliance partners (each of which is less than 8% of total ownership at December 31, 2007). Investments made by the Company after May 31, 2003 are recorded at cost. Investments made by the predecessor Company in one ethanol plant prior to May 31, 2003 was written down to zero as part of the purchase price allocation upon the acquisition of the Company by MSCP. In conjunction with our investment in Ace Ethanol, LLC and Indiana BioEnergy, LLC, we are entitled to a seat on each of these companies Board of Directors for as long as we maintain an ownership interest.

        Our marketing alliance contracts require us to purchase all of the production from these facilities and sell it at contract or prevailing market prices. The price at which we sell ethanol for our marketing alliance partners is the same price at which we sell our own production. The purchase price we pay our marketing alliance partners for their ethanol is based on an average price at which we sell ethanol, less the cost recovery component and commission. See "Item 1—Business—Distribution Strategy."

        Our marketing alliance is a major component of our growth strategy. Through these alliances, we believe we are able to increase sales and market share by using our existing marketing expertise and distribution systems without necessarily incurring the cost of constructing new ethanol production capacity. As the scale of the marketing alliances increase, we expect to increase our level of efficiency and customer service.

        Our marketing alliance is also beneficial to us on an industry-wide basis. By performing the marketing function for a myriad of individual plants, we are able to better supply a sizable and consistent volume of ethanol to meet customer demand overall.

Distribution and Logistics

        Our extensive logistics system is a key component to our customer service commitment. As of December 31, 2007, we have signed agreements for leased terminal capacity at 59 terminal locations, with 54 of these terminals in operation as of that date. The remaining contracts represent leases for additional terminals that have been signed, but which are not yet effective. We also have distribution agreements in place at December 31, 2007 for 8 rail to truck offloading distribution stations. There is no storage capacity at these distribution points other than the rail cars. With our leased terminal capacity, our rail to truck offloading stations, and our own and alliance partner production facilities in the Midwest, we believe our ethanol delivery system provides us with a significant competitive advantage. Our current network of terminals and rail to truck offloading distribution points creates an extensive distribution system that facilitates and enhances our ability to market ethanol. We and our marketing alliance partners deliver ethanol to these locations for onward distribution to the customers. At these locations, our ethanol is stored or blended with gasoline as it is loaded onto the customers' trucks. A large number of distribution locations enhances our marketing alliance strategy and purchase/resale operations through improved access to participating ethanol plants and improved distribution and storage capabilities.

        Under our terminal contracts, we generally lease space on both a fixed and throughput volume basis. Contracts are medium to long term in nature and are generally renewable subject to certain terms and conditions. The costs associated with leasing these terminals are factored into the purchase price we pay our marketing alliance partners for the ethanol that we purchase from them and, therefore, a portion of these leasing costs are effectively paid by our marketing alliance partners. See "Item 1—Business—Marketing Alliances."

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Legislative Drivers and Governmental Regulations

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

    The 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 established originally 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 by 2015.

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. 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 make it more expensive than domestic supplies derived from corn. This tariff was designed to protect the benefits of the federal tax subsidies for U.S. farmers. The tariff was originally $0.60 per gallon in addition to a 3.0% ad valorem duty. The tariff was subsequently lowered to $0.54 per gallon and was not adjusted completely in sync with the change in the blending credit. On December 20, 2006, the $0.54 per gallon tariff on foreign produced ethanol was extended until January 1, 2009.

        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 from 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 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

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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 Missouri and Oregon, have enacted mandates that currently require ethanol blends of 10% ethanol in motor fuel sold within the state. Another state, Minnesota, has a 20% renewable fuel mandate that goes into effect in 2012. 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 2007, 2006, and 2005, our 10 largest customers accounted for approximately 67%, 75%, and 77%, respectively, of our consolidated net revenue. Three of our customers, Exxon/Mobil, Shell and BP accounted for approximately 15%, 11% and 10%, respectively, of our consolidated 2007 revenue.

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, 2007, we had contracts for delivery of ethanol totaling 307.6 million gallons through December 2008. These commitments were for 62.8 million gallons at an average fixed price of $1.78 per gallon, 72.7 million gallons at an average spread to wholesale gasoline of a negative 45 cents per gallon (based upon the NYMEX, Chicago and NY harbor indices), and 172.1 million gallons at spot prices (using various Platt, OPIS and AXXIS indices). The majority of these contracts are for delivery in the first half of 2008.

Raw Materials and Suppliers

        Our principal raw material is #2 yellow corn. In 2007, 2006 and 2005, we purchased approximately 71.9 million, 51.0 million and 51.9 million bushels of corn, respectively. Our purchases of corn in 2007 increased significantly as a result of the addition of the Pekin dry mill which began grinding corn early in 2007.

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        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 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 previously 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 $0.3 million in 2007, $0.2 million in 2006, and $0.1 million in 2005.

Patents and Trademarks

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

Environmental and Regulatory Matters

        We are subject to extensive federal, state and local environmental laws, regulations and permit conditions (and interpretations thereof), including those relating to the discharge of materials into the air, 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. From time to time, hazardous material spills have occurred at our facilities or properties, which we investigate and remediate as necessary. Also, soil and groundwater contamination has been identified in the past at our Pekin, Illinois campus. If significant contamination is identified at our properties in the future, costs to investigate and remediate this

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contamination as well as any costs to investigate or remediate associated natural resource damages could be significant. 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 of 1980 ("CERCLA") 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 contamination or such third party claims. We have not accrued any amounts for environmental matters as of December 31, 2007. 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.

        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. These costs could have a material adverse affect 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 with other U.S. ethanol 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 ("VOC") emissions and other air emissions from many U.S. ethanol plants, including our Illinois and Nebraska facilities. The matter relating to our Illinois wet mill facility is still pending, and we could be required to install costly additional air pollution control equipment or take other measures to control air pollutant emissions at that 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 an indemnification payment from the former owner of our Nebraska facility relating to the cost of installing environmental controls at that facility related to an April 2005 consent decree with state authorities.

        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. In 2007, we spent approximately $5.8 million on these types of matters. We expect to have to eventually make significant capital expenditures to comply with the Environmental Protection Agency's ("EPA") final National Emissions Standard for Hazardous Air Pollutants, or NESHAP, under the federal Clean Air Act for industrial, commercial and institutional boilers and process heaters. This NESHAP was issued but

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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 certain of our boilers and process heaters. 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 boilers and process heaters.

        We currently generate revenue from the sale of carbon dioxide, which is a co-product of the ethanol production process at each of our 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, in 2007, Illinois and four other Midwestern States entered into the Midwestern Greenhouse Gas Reduction Accord, which program 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 require other costly carbon dioxide emissions reductions.

        For more information about our environmental compliance and actual and potential environmental liabilities, see "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Uses of Liquidity—Capital Expenditures," "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Environmental Matters," and "Item 1—Business—Environmental Matters."

Employees

        At December 31, 2007, we had a total of 331 full-time equivalent employees. Approximately 51% 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, that expires in June 2009. As a whole, we believe our relations with our employees are good.

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Item 1A.    Risk Factors

We have invested excess cash in auction rate securities ("ARS"). Should we not be able to liquidate a substantial portion of the remaining portfolio of these ARS securities on a timely basis and on acceptable terms, we will have to either attempt to raise additional funds or slow down the construction of our new facilities, or both. In addition, delays in the construction of our new facilities could expose us to material penalties.

        At December 31, 2007, we had invested $211.5 million in taxable ARS which we classified as current assets. We consider these securities as available for sale. The ARS held by the Company are private placement securities with long-term stated maturities for which the interest rates are reset through a Dutch auction every 28 days. The auctions have historically provided a liquid market for these securities as investors historically could readily sell their investments at auction. With the liquidity issues experienced in global credit and capital markets, the ARS held by the Company have experienced multiple failed auctions, beginning on February 8, 2008, as the amount of securities submitted for sale has exceeded the amount of purchase orders.

        These securities may not provide the liquidity to us as we need it, as it could take until the final maturity of the underlying notes (up to 35 years) to realize our investments' recorded value. Currently, there is a very limited market for any of these securities and further liquidations at this time, if possible, would likely be at a significant discount. Accordingly, we do not currently intend to attempt to liquidate any more of these securities until market conditions improve or our liquidity needs require us to do so. Cash and cash equivalents as of December 31, 2007 was $17.2 million. Successful ARS liquidations completed in 2008 generated $82.8 million. At December 31, 2007, we also had availability under our secured revolving credit facility of $122.6 million. Our total estimated remaining expenditures needed to complete our two new facilities at December 31, 2007 are estimated to be between $295 million and $305 million approximately evenly spent over the balance of the construction period through the first quarter of 2009. After utilization of our current available resources, should we not be able to liquidate a substantial portion of the remaining portfolio of these ARS securities on a timely basis and on acceptable terms, we will have to either attempt to raise additional funds or slow down the construction of our new facilities, or both. In addition, delays in the construction of our new facilities could expose us to material penalties.

We operate in a highly competitive industry with low barriers to entry. In addition, if the expected increase in ethanol demand does not occur, or if the demand for ethanol otherwise decreases, there may be excess capacity in our industry.

        In the U.S., we compete with other corn processors and refiners, including Archer-Daniels-Midland Company, VeraSun 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 2007, the top ten domestic producers accounted for approximately 54% of all production capacity, and there has been substantial consolidation activity in the industry which we expect to continue. If our competitors consolidate or otherwise grow and/or we are unable to similarly increase our size and scope, our business and prospects may be significantly and adversely affected.

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

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        Moreover, domestic capacity has increased significantly from 1.3 billion gallons per year in 1997 to 7.5 billion gallons per year at the end of 2007. In addition, there is a significant amount of ethanol capacity currently under construction. According to the RFA, as of December 2007, approximately 5.8 billion gallons per year of production capacity is currently under construction. We believe that this capacity is being added primarily to address anticipated increases in demand. Demand for ethanol may not increase as quickly as expected or to a level that exceeds supply, or may not increase at all. If the ethanol industry has excess capacity and such excess capacity results in a fall in prices, it may have a significant adverse impact on our results of operations, cash flows and financial condition. Excess capacity may result from the increases in capacity coupled with insufficient demand. Demand could be impaired due to a number of factors, including lack of infrastructure, distribution issues, regulatory developments and reduced U.S. gasoline consumption. Reduced gasoline consumption could occur as a result of increased gasoline or oil prices. For example, the price of oil hit $100 per barrel in December 2007. Gasoline price increases could cause businesses and consumers to reduce driving or acquire vehicles with more favorable gasoline mileage. There is some evidence that this has occurred in the recent past as U.S. gasoline prices have increased. Demand for ethanol can also fall if gasoline prices decrease because ethanol is used as a potential substitute for gasoline.

        During 2007, our results of operations were negatively impacted because of the perception that the current capacity being built would outstrip demand. In addition, our top customers are oil companies which make significant profits from the sale of gasoline. As such they may oppose the discretionary blending of gasoline with ethanol in excess of that mandated by law. Our competitors 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 2007, we purchased approximately 71.9 million bushels of corn at a cost of $270.4 million, which comprised about 68% of our total cost of production. In 2007, our average corn cost ranged from a low of $3.19 per bushel in January 2007 to a high of $4.06 per bushel in June 2007. Corn prices began to rise significantly beginning in September 2006. We believe that a systemic shift has occurred in the marketplace for corn, and that price of corn will remain significantly higher than the historical average. 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.

        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

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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 historically high.

        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 engage in hedging transactions which involve risks that can harm our business."

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, is principally dependent on the spread between ethanol and corn prices. The spread between ethanol and corn prices narrowed significantly in the second half of 2007 as ethanol prices fell while, at the same time, corn prices increased. Any reduction in the spread between ethanol and corn prices, whether as a result of an increase in corn prices or a reduction in ethanol prices, would adversely affect our financial performance. If the spread decreases below a certain level, we will likely experience losses.

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 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 provides a tax credit of 5.1 cents per gallon on 10% ethanol blends that is set to expire in 2010, (3) the small ethanol producer tax credit, for which we do not qualify because of the size of our ethanol plants, and

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(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.

Waivers or repeal of the RFS minimum levels of renewable fuels included in gasoline could have a material adverse affect on our results of operations.

        Shortly after passage of the Energy Independence and Security Act of 2007 in December 2007, which increased the minimum mandated required usage of ethanol, a Congressional sub-committee held hearings on the potential impact of the new RFS on commodity prices. While no action was taken by the sub-committee towards repeal of the new RFS, any attempt by Congress to re-visit, repeal or grant waivers from the new RFS could adversely affect demand for ethanol and could have a material adverse effect on our results of operations and financial condition.

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 $0.51 per gallon ethanol subsidy currently available under the federal excise tax incentive program for refineries and blenders that mix ethanol with their gasoline. On December 20, 2006, the tariff on foreign produced ethanol was extended until January 1, 2009. At a certain price level, imported ethanol may become profitable for sale in the U.S. despite the tariff. This occurred in 2006, due to a spike in the ethanol prices and insufficient supply. As a result, there may effectively be a ceiling on U.S. ethanol prices. This, combined with uncertainties surrounding U.S. producers ability to meet domestic demand, resulted in significant imports of ethanol, especially from Brazil. Furthermore, East Coast facilities are better suited to bringing in product by water rather than rail (the preferred path for ethanol from the Midwest). The combination made it more economic for some buyers to import ethanol with the full import duty than to bring supplies from the Midwest. Given the increase in ethanol demand as a result of the new RFS and potential transportation bottlenecks delivering material from the Midwest, imports of ethanol could rise.

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

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

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

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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. From time to time, hazardous material spills have occurred at our facilities or properties, which we investigate and remediate as necessary. Also, soil and groundwater contamination has been identified in the past at our Pekin, Illinois campus. If significant contamination is identified at our properties in the future, costs to investigate and remediate this contamination as well as any costs to investigate or remediate associated natural resource damages could be significant. If any of these sites are subject to investigation and/or remediation requirements, we may be responsible under CERCLA 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, 2007. 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.

        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. These costs could have a material adverse affect 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 with other U.S. ethanol 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 VOC emissions and other air emissions from many U.S. ethanol plants, including our Illinois and Nebraska facilities. The matter relating to our Illinois wet mill facility is still pending, and we could be required to install costly additional air pollution control equipment or take other measures to control air pollutant emissions at that 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 an indemnification payment from the former owner of our Nebraska facility relating to the cost of installing environmental controls at that facility related to an April 2005 consent decree with state authorities.

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        We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits. In 2007, we spent approximately $5.8 million on these types of matters. We expect to have to eventually make significant capital expenditures to comply with the EPA's final National Emissions Standard for Hazardous Air Pollutants, or NESHAP, under the federal Clean Air Act 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 certain of our boilers and process heaters. 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 boilers and process heaters.

        We currently generate revenue from the sale of carbon dioxide, which is a co-product of the ethanol production process at each of our 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, in 2007, Illinois and four other Midwestern States entered into the Midwestern Greenhouse Gas Reduction Accord, which program 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 require other costly carbon dioxide emissions reductions.

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 hedging positions in the commodities. 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 hedging activities to sales plans and pricing activities, occasionally such hedging activities can themselves result in losses. There can be no assurance that such 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 our alliance partner 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

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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.

        Any disruptions at our alliance partners' facilities could have a material adverse effect on our results of operations and financial condition. We agree through our alliance partner agreements to purchase all fuel grade ethanol produced by our alliance partners and title to the product transfers to us when product is loaded. Any disruptions at the alliance partners' facilities could affect our ability to meet our customers' demands. As a result of a disruption at an alliance facility we may have to purchase ethanol from the spot market.

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 (including hurricanes), 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 eight year period from 1999 through December 31, 2007, 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 3.7 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 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, 2007 we had contracted to sell 62.8 million gallons of ethanol at an average fixed price of $1.78. We have also contracted to sell 72.7 million gallons of ethanol at an average negative spread of $0.45 per gallon to the wholesale value of gasoline at the time of delivery and 172.1 million gallons of ethanol at the spot price at the time of delivery. These contracts provide for delivery throughout 2008, but they are heavily weighted towards the first and second quarters of 2008.

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

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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 and can significantly increase or decrease our profitability.

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.

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 226 million gallon plant in Mount Vernon, Indiana. In addition, we are obligated to add an additional 113 million gallons of capacity through a phase II expansion in Mt. Vernon, Indiana, and would be subject to material penalties if we do not.

        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" 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. If we 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 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 March 1, 2009 and substantial completion of phase II (an additional 110 million gallons of capacity) by January 1, 2011, subject in the case of the 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 alternations, (ii) without terminating the lease, require us 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. In addition, under the design build agreements for the initial 113 million gallon capacity expansion at each of Mt Vernon and Aurora, we have the ability to delay construction by up to 180 days. If we do so, we will be responsible for certain

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increased costs and foregone profit of the contractor (potentially including an early completion bonus). If we were to delay construction beyond 180 days the contractor would be entitled to treat the delay as a termination by us for convenience and we would be responsible for certain costs and expenses of the contractor in connection with such termination as well as a termination fee of 1% of the total EPC contract sum.

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 British Petroleum 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 British Petroleum and DuPont have not announced a timeline for producing biobutanol on a large scale, if biobutanol production comes online in 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 such that you could lose some or all of your investment.

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, 2007, approximately 51% 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

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Steelworkers International Union, Local 7-662, that expires in June 2009. Any labor dispute by any of our employees, or our customers' employees, could again have a significant negative effect on our financial results and operations.

We depend on our marketing alliance contracts for a majority of the gallons we sell and significant synergies. We may be adversely affected by decreases in marketing alliance volumes resulting from the acquisition of marketing alliance partners by our competitors, the reduction of production capacity or abandonment of announced projects by marketing alliance partners, the creation of similar marketing alliances by our competitors and other failures to renew marketing alliance contracts.

        We source a significant amount of the ethanol that we sell from our marketing alliance partners. Although their contribution to our operating income is limited, these marketing alliance contracts contribute significantly to our market presence and enable us to meet major ethanol consumer needs and leverage our marketing expertise and distribution systems. Our marketing alliance contracts typically have a two year term and automatically renew for additional one year terms unless either party elects to terminate in advance. Over the past several years a number of marketing alliance partners have elected not to renew their marketing alliance contracts for a variety of reasons, including the acquisition of the marketing alliance partner by a competitor, the marketing alliance partner's view that it could reduce freight costs by marketing its ethanol outside of our marketing alliance and the creation of similar marketing alliances by our competitors. We cannot give assurance that we will be able to renew our existing marketing alliance contracts or enter into similar contracts with other ethanol producers.

        In addition, the substantial majority of our projected marketing alliance gallons relate to projects to construct ethanol production facilities that have been announced but construction has not commenced. Given current industry and financial market conditions it is uncertain whether any or all of these plants will be built as scheduled or at all. Accordingly, we may be unable to realize our anticipated growth in marketing alliance volumes and the related benefits.

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 Holdings LLC, the MSCP funds beneficially own approximately 28.2% 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, currently are 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.

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Our less than 100% ownership of Nebraska Energy, LLC ("NELLC") and the supermajority provisions contained in the operating agreement that governs NELLC may restrict our ability to govern and manage our business.

        We own 78.4% of NELLC which owns our Nebraska facility. The other 21.6% is owned by Nebraska Energy Cooperative, an agricultural cooperative comprised of over 200 corn producers. NELLC is governed by an operating agreement which, among other things, requires a vote of holders of at least 80% of the outstanding member interests before NELLC may undertake certain actions, including, but not limited to the following:

    loans or advances to or investments in any other person, other than in the ordinary course of business;

    acquisitions of capital assets or other capital expenditures during any taxable year in excess of certain specified thresholds;

    the sale, lease or disposition of the property having a fair market value in excess of certain specified thresholds;

    borrowings (including under capitalized leases, but excluding trade payables in the ordinary course of business) or the grant or creation of any security interest or other lien on any of NELLC's property;

    the guarantee or assumption of any liability or obligation of any person, except in the ordinary course of business;

    except as provided in the operating agreement, the acquisition of any member's interests in NELLC by redemption or otherwise;

    the engagement of any member or affiliate of any member to provide any services or perform any functions to or for NELLC (such as renting office space, providing accounting services, providing self-insurance or allocations of any member overhead to NELLC); and

    any transaction not in the "ordinary course of business or affairs" or "in the usual way of business and affairs" of NELLC.

        The operating agreement also contains provisions which require NELLC to obtain the approval of holders of at least 80% of the membership interests in order to distribute an amount in excess of 60% of its annual taxable income (as defined in the operating agreement).

        These provisions may limit our ability to quickly and adequately respond to changes in the business environment and may restrict our ability to manage the NELLC facility in a manner that benefits our Company as a whole. For example, we may not be able to access additional financing unless we can obtain the guarantee of NELLC or a pledge of its assets, and the other members of NELLC may not approve such a guarantee or pledge. These provisions limit our ability to transfer cash from the NELLC to meet our obligations.

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.

32



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

        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.

The loss of any of our major customers could adversely affect our revenue and financial health.

        In 2007 and 2006, our 10 largest customers accounted for approximately 67% and 75%, respectively, of gallons sold. If we were to lose any of our relationships with these customers, our revenue, and results of operations and financial condition might suffer.

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;

33


    inclement weather and natural disasters;

    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. For example, during the second half of 2007, we experienced operational issues at our Pekin, Illinois wet mill. These operational issues reduced the amount of ethanol and co-products produced by this facility during that time period.

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 able to incur substantial debt. This could further exacerbate the risks that we and our subsidiaries face.

        We and our subsidiaries are able to incur 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.

Any acquisitions or developments we complete could dilute your ownership interest in us or have a material adverse affect on our financial condition and operating results.

        The integration of any acquisition or facility development into our business may result in unforeseen operating difficulties and may require significant financial and managerial resources that would otherwise be available for the ongoing development or expansion of our existing operations. Future acquisitions or facility developments may involve the issuance of our equity securities as

34



payment or in connection with financing the business or assets acquired. Consummating these transactions could also result in the incurrence of additional debt and related interest expense, as well as unforeseen liabilities, all of which could have a material adverse effect on our financial condition and operating results.

        In addition, other marketing alliances exist and additional alliances may be formed which would compete to market production, including production of our current marketing alliance partners. These competing alliances could persuade our current partners not to renew their agreements or could cause the terms of future contracts to be less favorable to us. If we lose marketing partners to competing marketing alliances or are unable to add new producers to our alliance, our results of operations may be adversely affected.

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:

    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;

    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 3, 2007 to December 31, 2007, the average daily trading volume of our common stock as reported by Bloomberg L.P. was approximately 860,000 shares. It is uncertain whether a more active trading market in our common stock will develop. If 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, and we may also issue additional shares of common stock to finance future acquisitions. 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

35



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.

Item 1B.    Unresolved Staff Comments

        There are no unresolved comments.

36


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, 2007

  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. The Pekin facility also houses our corporate staff.

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.

37


Facilities Currently Being Constructed:


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 fully-denatured ethanol annually. The Company is currently constructing phase I with an annual production capability of 113 million gallons of fully-denatured ethanol annually.

Mount Vernon, IN

 

Leased(1)

 

113

 

Dry

 

116

 

The Company leases this property from the State of Indiana with the obligation of developing and operating a 226 million gallon ethanol facility. The company is currently constructing the first phase of an ethanol production facility on this site with a capability to produce 113 million gallons of fully-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.

(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 as described under "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Environmental Matters" and incorporated herein by reference. We are not involved in any legal proceedings that we believe could have a material adverse effect upon our business, operating results or financial condition.

Item 4.    Submission of Matters to a Vote of Security Holders

        No matters were submitted to a vote of security holders during the fourth quarter of 2007.

38



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 41,971,330 shares of Common Stock outstanding, held by 23 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. Our shares began trading on the New York Stock Exchange on June 29, 2006:

 
  2007
  2006
Period

  High
  Low
  High
  Low
First Quarter   $ 23.56   $ 14.78     n/a     n/a
Second Quarter   $ 20.68   $ 13.97   $ 39.05   $ 38.37
Third Quarter   $ 18.34   $ 10.14   $ 40.28   $ 19.45
Fourth Quarter   $ 13.27   $ 7.81   $ 25.58   $ 19.51

Dividends

        We did not declare or pay cash dividends on our Common Stock during the years ended December 31, 2007, 2006 or 2005. 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. We intend to retain earnings to support the growth of our business. 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.

Issuer Purchases of Equity Securities

        The following table presents information with respect to repurchases of Common Stock made by the Company during the quarter ended December 31, 2007. All of the repurchased shares were purchased on the open market under a share repurchase plan approved by the Board of Directors.

Period

  Total Number of Shares Purchased
  Average Price
Paid Per Share(1)

  Total Number of
Shares Purchased
as Part of
Publicly Announced
Plans or Programs

  Approximate
Dollar Value
that May Yet Be
Purchased Under the
Plans or Programs

10/01/07–10/31/07     $     $ 47,855,000
11/01/07–11/30/07   248,315     8.01   369,615     45,866,000
12/01/07–12/31/07             45,866,000
   
 
 
 
Total   248,315   $ 8.01   369,615   $ 45,866,000
   
 
 
 

(1)
Average price paid per share reflects the average share price paid for Aventine Common Stock on the business day the shares were repurchased on the open market.

39


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

GRAPHIC

TOTAL CUMULATIVE RETURNS

 
  2006
  2007
Company

  June
  September
  December
  March
  June
  September
  December
Aventine Renewable Energy Holdings, Inc.    $ 100   $ 50   $ 55   $ 42   $ 39   $ 25   $ 30
S&P 500 Index     100     105     113     113     120     123     119
Custom Composite Index (2 stocks)     100     62     74     77     57     43     53

Aventine's total return assumes an investment of $100 at the Company's initial public offering price of $43 per share and shows what the $100 investment would be worth at the indicated date.

The Custom Composite Index consists of Verasun Energy Corporation. and Pacific Ethanol, Inc.

Copyright © 2008, Standard & Poor's, a division of The McGraw-Hill Companies, Inc. All rights reserved.

40


Equity Compensation Plan Information

        The following table provides information about our equity compensation plan as of December 31, 2007:

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)   3,612,460   $ 8.10 (2) 3,088,712
Equity compensation plans not approved by security holders   0         0
  Total   3,612,460         3,088,712

(1)
Aventine Renewable Energy Holdings Inc. 2003 Stock Incentive Plan, as amended through March 22, 2007. The amount shown in column (a) consists of 3,515,883 stock options, 78,591 shares of restricted stock and 17,986 restricted stock units.

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

41


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, 2007 and 2006 and the statement of operations data presented below for each of the years in the three-year period ended December 31, 2007, are derived from our audited Consolidated Financial Statements beginning on page F-1. The other balance sheet data and statement of operations data for the seven months ended December 31, 2003, and for the five months ended May 30, 2003 presented below, is derived from our previously audited Consolidated Financial Statements included in our S-1 registration statement, which is not presented herein.

 
  Year Ended December 31,
   
   
 
 
  Period from May 31 to December 31, 2003
  Period from January 1 to May 30, 2003
 
(in thousands, except per share amounts)
  2007
  2006
  2005
  2004
 
 
   
   
   
   
   
  Predecessor Historical(1)

 
Statement of Operations Data:  
Net sales   $ 1,571,607   $ 1,592,420   $ 935,468   $ 858,876   $ 404,389   $ 271,379  
Cost of goods sold     1,497,807     1,460,806     848,053     793,070     375,042     270,242  
   
 
 
 
 
 
 
Gross profit     73,800     131,614     87,415     65,806     29,347     1,137  

Selling, general and administrative expenses

 

 

36,367

 

 

28,328

 

 

22,500

 

 

16,236

 

 

6,986

 

 

6,278

 
Other expense (income)     (1,113 )   (3,389 )   (989 )   (3,196 )   (161 )   210  
   
 
 
 
 
 
 
Operating income (loss)     38,546     106,675     65,904     52,766     22,522     (5,351 )

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Interest expense     (16,240 )   (9,348 )   (16,510 )   (2,035 )   (419 )   (4,226 )
  Interest income     12,432     4,771     2,218     19     4     3  
  Loss on early extinguishment of debt         (14,598 )                
  Other non-operating income (expense)     (78 )   3,654     1,781     (924 )   (2,560 )   1,024  
  Minority interest     (1,338 )   (4,568 )   (2,404 )   (2,148 )   (1,025 )   378  
   
 
 
 
 
 
 
Income (loss) before income taxes     33,322     86,586     50,989     47,678     18,522     (8,172 )
Income tax expense (benefit)     (477 )   31,685     18,807     18,433     7,473     (3,269 )
   
 
 
 
 
 
 
Net income (loss)   $ 33,799   $ 54,901   $ 32,182   $ 29,245   $ 11,049   $ (4,903 )
   
 
 
 
 
 
 
Income (loss) per common share—basic(4)   $ 0.81   $ 1.43   $ 0.93   $ 0.84   $ 0.32   $ (0.14 )
Basic weighted-average common shares     41,886     38,411     34,686     34,684     34,643     34,643  

Income (loss) per common share—diluted

 

$

0.80

 

$

1.39

 

$

0.89

 

$

0.82

 

$

0.32

 

$

(0.14

)
Diluted weighted-average common and common equivalent shares     42,351     39,639     36,052     35,768     34,643     34,643  

Other Data:
(In thousands, except per bushel and per gallon amounts)

 
Gallons sold     690,171     695,784     529,836     505,251     271,344     n/a  
EBITDA(3)   $ 49,708   $ 109,475   $ 67,555   $ 51,281   $ 19,718     n/a  
Capital expenditures   $ 235,211   $ 76,499   $ 20,675   $ 4,653   $ 2,952     n/a  
Average price per gallon of ethanol sold   $ 2.08   $ 2.18   $ 1.63   $ 1.55   $ 1.21     n/a  
Average price of corn per bushel   $ 3.76   $ 2.41   $ 2.08   $ 2.68   $ 2.42     n/a  

42



Balance Sheet Data:
(in thousands, at period end)

 
Total assets   $ 762,185   $ 408,136   $ 221,977   $ 163,598   $ 106,449   $ 89,805  
Total debt(2)   $ 300,000       $ 161,514     172,791     3,922     152,759  
Stockholders' equity (deficit)   $ 343,871   $ 304,163   $ (20,654 ) $ (56,581 )   (53,785 )   n/a  

(1)
The financial statements for the period from January 1, 2003 to May 30, 2003 were prepared using the historical basis of accounting applied by the subsidiary of The Williams Companies, Inc. which owned and operated our business prior to May 30, 2003. These financial statements are designated as "Predecessor" because they are not comparable to our operating and cash flow results subsequent to our acquisition by the MSCP funds.

(2)
Total debt includes amounts outstanding under our revolving credit agreement and, in 2007, our 10% fixed-rate unsecured notes; in 2005 and 2004, our previous outstanding senior, secured floating rate notes; and in periods prior to May 31, 2003, intercompany debt on our predecessors business was financed by its parent.

(3)
EBITDA is defined as earnings before interest expense, interest income, income tax expense, depreciation, and loss on the early extinguishment of debt. EBITDA is not a measure of financial performance under accounting principles generally accepted in the United States and should not be considered an alternative to net earnings or any other measure of performance under accounting principles generally accepted in the U.S. or to cash flows from operating, investing or financing activities as an indicator of cash flows or as a measure of liquidity. 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.

(4)
Pro forma net income (loss) per common share of our predecessor is based upon the weighted-average number of shares of common stock outstanding at the inception of the Company.


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

 
  For the Years Ended December 31,
   
 
 
  Period from May 31 to December 31, 2003
 
(In thousands)
  2007
  2006
  2005
  2004
 
Net income   $ 33,799   $ 54,901   $ 32,182   $ 29,245   $ 11,049  
Depreciation     12,578     3,714     2,274     1,587     781  
Interest expense     16,240     9,348     16,510     2,035     419  
Loss on early extinguishment of debt         14,598              
Interest income     (12,432 )   (4,771 )   (2,218 )   (19 )   (4 )
Income tax expense/(benefit)     (477 )   31,685     18,807     18,433     7,473  
   
 
 
 
 
 
Earnings before interest, taxes, depreciation and amortization   $ 49,708   $ 109,475   $ 67,555   $ 51,281   $ 19,718  
   
 
 
 
 
 

        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.

43


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, 2007 should be read in conjunction with the Consolidated Financial Statements, and related notes beginning on page F-1.

Overview

        We are a leading producer and marketer of ethanol based on both the number of gallons produced and sold. Through our own production facilities, marketing alliances with other ethanol producers and our purchase/resale operations, we market and distribute ethanol to many of the leading energy companies in the U.S. We have a comprehensive national distribution network utilizing our leased railcar and barge fleet and terminal network structure at critical points on the nation's transportation grid where our ethanol is blended with our customers' gasoline. We are also a marketer of bio-diesel. In addition to producing ethanol, our facilities also produce several by-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.

        Because we market and sell ethanol without regard to whether we produced it, are reselling it, or are marketing it for our marketing alliance partners, 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 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 89% of capacity during the fourth quarter of 2007 and 93% for the full year as compared to 89% for the full year 2006.

        Besides our own equity ethanol production, we also generate revenue by selling ethanol that we purchase from our marketing alliance partners. See "Item 1—Business—Marketing Alliances." We signed our first marketing alliance agreement in 2001 and as of December 31, 2007 have increased the program to 13 alliance contracts with operating third-party plants that have the capacity to produce 504 million gallons of ethanol annually. As of December 31, 2007, we have signed additional marketing alliance contracts with new alliance partners that have either announced new ethanol production facilities or have facilities currently under construction which are expected to produce an additional 1.5 billion gallons of ethanol per year when completed. Of this amount, 416 million gallons is currently under construction and 1.1 billion gallons is under development but not yet under construction. There can be no assurances that any or all of the projects under construction will be completed on a timely basis or at all and, given current industry and financial market conditions, it is uncertain whether any or all of the plants not yet under construction will be commenced or completed as scheduled or at all. We expect revenue and marketing alliance production to significantly increase in 2008 as those marketing alliance partner plants currently under construction come online.

        We also resell ethanol and bio-diesel that we purchase from third-party producers and marketers.

        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

44



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 have identified opportunities to increase our equity production capacity through the development of new production facilities and are continually exploring potential acquisition opportunities. In addition to the 57 million gallon dry mill expansion of our Pekin, Illinois facility which was completed in early 2007, we have begun construction of 113 million gallon annualized capacity ethanol production facilities at both Mt. Vernon, Indiana and Aurora, Nebraska where we expect to begin ramping up ethanol production in the first quarter of 2009.

        We are also obligated to add an additional 113 million gallons of capacity at Mt. Vernon, Indiana through a phase II expansion and would be subject to material penalties if we do not. In addition, we intend to also add an additional 113 million gallons of capacity through a phase II expansion at Aurora, Nebraska, along with potentially expanding our existing Pekin, Illinois campus. The timing of the expansions will be based upon, among other factors, market conditions and the availability of financing on attractive terms.

Executive Summary

        We generated net income of $33.8 million, or $0.80 per diluted share in 2007, as compared to net income of $54.9 million, or $1.39 per diluted share, in 2006. Net income decreased primarily as a result of significantly higher corn costs, a lower realized average price per gallon of ethanol sold and lower volumes. In addition, higher selling, general and administrative expenses, including costs associated with being a public company and from the expansion and growth of our business, also attributed to the decline in net earnings. Revenue in both 2007 and 2006 was approximately $1.6 billion.

        Gallons of ethanol sold in 2007 decreased slightly, to 690.2 million, as compared to 695.8 million in 2006. Ethanol production for 2007 totaled 192.0 million gallons, up from 133.0 million gallons in 2006. The higher equity production related to the new Pekin dry mill was not enough to offset the lower availability of marketing alliance gallons available to sell. 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, which was offset somewhat by additions to our marketing alliance throughout the year. By year end 2007, we have essentially replaced all of the gallons caused by the loss of the alliance partner in the first quarter of 2007. Ethanol purchased from other producers and marketers was higher in 2007 versus 2006.

        Gross profit for 2007 totaled $73.8 million, a decrease of $57.8 million from 2006. The decline in gross profit was principally the result of a significantly lower commodity spread (defined as the gross selling price per gallon of ethanol less net corn cost per gallon) caused by significantly higher corn prices and lower average ethanol prices. This was partially offset by increased co-product revenue. Lower volumes sold in 2007 also affected gross profit. The average sales price per gallon of ethanol in 2007 was $2.08 per gallon, down from $2.18 per gallon in 2006. Every 1 cent decline in the price of ethanol requires approximately a 4 cent decline in the per bushel price of corn (assuming a 30% co-product return and a 2.8 gallon per bushel yield) to maintain the same spread. Our corn costs during 2007 averaged $3.76 per bushel, significantly higher than our 2006 cost of $2.41 per bushel.

        The average inventory cost of $1.80 per gallon at the end of 2007 versus $1.91 at the end of 2006 reflects the year over year decline in ethanol pricing 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. The economic impact of this same issue in 2006 was a reduction in cost of goods sold of approximately $10.3 million, as inventory values increased from $1.50 per gallon at the

45



end of 2005 to $1.91 per gallon at the end of 2006. 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. Changes, either upward or downward, in our purchased cost of ethanol or our own production costs, will cause the inventory value to fluctuate from period to period, perhaps significantly. These changes in value flow through our statement of operations as the inventory is sold and can significantly increase or decrease our profitability.

        Significantly higher selling, general and administrative expenses ("SG&A") in 2007 also led to a decrease in net income. In 2007, SG&A costs were $36.4 million, an increase of 8.1 million or 28.6%, over 2006's total of $28.3 million. SG&A costs increased as a result of higher costs associated with being a public company and from the expansion and growth of our business.

        An audit of our federal income tax returns covering fiscal years 2004 and 2005 by the Internal Revenue Service ("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 includes its previously recorded liability for uncertain tax benefits, the related interest and the release of code Section 382 valuation allowances.

Non-Recurring Charges

        As a result of the repurchase of our senior secured floating rate notes in 2006, the Company recorded a pre-tax charge in 2006 of $14.6 million comprised of (i) $8.9 million for the tender and consent premiums and related fees and expenses, (ii) $4.9 million for the write-off of unamortized debt issuance costs, and (iii) $0.8 million for the write-off of unamortized deferred debt costs related to our amended credit agreement. These charges reduced diluted earnings per share by $0.24 per share in 2006.

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, and from the cost of corn. 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 the price of oil and gasoline and other market factors. 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.

46


Impact of Product Mix

        Ethanol we sell is obtained from three sources: ethanol we produce, ethanol purchased from marketing alliance partners and ethanol from purchases we may make under our purchase/resale program. While our marketing alliance and purchase/resale businesses are important to our overall strategies, the great majority of our gross profit comes from our own equity production. Our overall profitability from period to period is affected by the mix of sales within these categories.

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.

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. We consider these securities as available for sale. The ARS held by the Company are private placement securities with long-term stated maturities for which the interest rates are reset through a Dutch auction every 28 days. The auctions have historically provided a liquid market for these securities as investors historically could readily sell their investments at auction. With the liquidity issues experienced in global credit and capital markets, the ARS held by the Company have experienced multiple failed auctions, beginning on February 8, 2008, as the amount of securities submitted for sale has exceeded the amount of purchase orders.

        Prior to December 31, 2007, we began to exit our position in these securities and continued to do so subsequent to December 31, 2007. As of February 21, 2008, we had successfully liquidated $84.3 million of these securities, thereby leaving us with $127.2 million invested in ARS as of February 21. We incurred a pre-tax loss of approximately $1.5 million in connection with these liquidations. Our remaining ARS consist of various tranches of notes issued by two issuers, College Loan Corporation Trust I and NextStudent Master Trust I. All of these securities continue to carry AAA/Aaa ratings, have not experienced any payment defaults and are backed by student loans which carry guarantees as provided for under the Federal Family Education Loan Program of the U.S. Department of Education. Nonetheless, if uncertainties in the credit and capital markets continue, these markets deteriorate further or there are any ratings downgrades on any ARS we hold, we may be required to recognize impairments and/or reclassify these investments from short-term to long-term investments.

        In addition, these securities may not provide the liquidity to us as we need it, as it could take until the final maturity of the underlying notes (up to 35 years) to realize our investments' recorded value. Currently, there is a very limited market for any of these securities and further liquidations at this time, if possible, would likely be at a significant discount. Accordingly, we do not currently intend to attempt to liquidate any more of these securities until market conditions improve or our liquidity needs require us to do so.

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Share-based Compensation Expense

        Effective January 1, 2006, we adopted, on a modified prospective transition method, 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. We previously accounted for share-based compensation expense using SFAS 123, using the minimum value method. In accordance with the modified prospective transition method, our financial statements for prior periods have not been restated to reflect, and do not include, the impact of SFAS 123(R). 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, 2007 and 2006 included 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 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 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 are estimated using a 3% forfeiture rate. The expected option term is calculated using the "simplified" method permitted by SAB 107. Our options have characteristics significantly different from those of traded options, and changes in the assumptions can materially affect the fair value estimates.

Inventory

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

Derivatives and Hedging Activities

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

        We apply the provisions of 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

48



derivatives. These derivative 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 (loss). The fair value of these derivative assets is recognized in other current assets or 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 may be exempted 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's contracts that meet the requirements of normal are documented as normal and exempted from the accounting and reporting requirements of SFAS 133.

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, inventories, prepaid pension, postretirement benefit obligations, and certain other accrued liabilities are the primary sources of these temporary differences. Deferred income tax also includes tax credit 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 $0.5 million for the years ended December 31, 2007 and 2006, and $0.6 million for the year ended December 31, 2005. Total estimated pension and postretirement expense in 2008 is expected to be approximately $0.5 million. 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 2007, 2006 and 2005 of $0.5 million, $2.0 million and $0.3 million, respectively. In 2008, we expect to make contributions totaling $0.9 million to our defined benefit plan.

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

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

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

49


Recent Accounting Pronouncements

        In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 ("SFAS 157"), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of SFAS 157 to have a significant impact on our consolidated financial position or results of operations.

        In February 2007, The FASB issued 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. SFAS No. 159 permits a company to choose to measure many financial instruments and other items at fair value that are not currently required to be measured at fair value. The objective is to improve financial reporting by providing a company with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. A company shall report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. SFAS No. 159 will be effective for fiscal years that begin after November 15, 2007. We do not believe that the adoption of SFAS No. 159 will have a significant impact on our consolidated financial position or results of operations.

        In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141-R ("SFAS 141R"), Business Combinations, which revised Statement of Financial Accounting Standards No. 141, Business Combinations ("SFAS 141"). SFAS 141R is effective for business combinations for fiscal years beginning after December 15, 2008. Under SFAS 141, organizations utilized the announcement date as the measurement date for the purchase price of the acquired entity. SFAS 141R requires measurement at the date the acquirer obtains control of the acquiree, generally referred to as the acquisition date. SFAS 141R will have a significant impact on the accounting for transaction costs, restructuring costs as well as the initial recognition of contingent assets and liabilities assumed during a business combination. Under SFAS 141R, adjustments to the acquired entity's deferred tax assets and uncertain tax position balances occurring outside the measurement period are recorded as a component of the income tax expense, rather than goodwill. As the provisions of SFAS 141R are applied prospectively, the impact cannot be determined until the transactions occur.

        In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160 ("SFAS 160"), Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51. SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Among other requirements, SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is to be reported as a separate component of equity in the consolidated financial statements. SFAS also requires consolidated net income to include the amounts attributable to both the parent and the noncontrolling interest and to disclose those amounts on the face of the consolidated statement of income. SFAS 160 must be applied prospectively for fiscal years, and is effective for fiscal years beginning after December 15, 2008 except for the presentation and disclosure requirements, which will be applied retrospectively for all periods presented.

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Results of Operations

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

        Total gallons sold in 2007 were 690.2 million gallons, versus 695.8 million gallons sold in 2006, a decrease of 5.6 million gallons. Ethanol gallons sourced were 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 )%
   
 
 
 
 

*
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 Pekin 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 continuing to outpace 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 costs for motor fuel taxes which have been billed to customers.

        Purchased ethanol in 2007 totaled $972.5 million, versus approximately $1.1 billion in 2006. The decrease in purchased ethanol results 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

51



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 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 and amortization. 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 is due to a combination of increased bushels of corn consumed by the new Pekin dry mill which came online 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 93% of capacity for 2007 as compared to 89% for 2006.

        Depreciation for 2007 totaled $12.6 million, versus $3.7 million in 2006. The increase in depreciation expense is 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 is principally from the expansion of our distribution system footprint, along with higher general freight and barge expenses. Fuel surcharges continue to impact general freight rates.

        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 reflect 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.

        Interest income in 2007 was $12.4 million, versus $4.7 million in 2006. The increase in interest income is 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 reflects interest incurred from March 2007 through December 2007 on our $300 million aggregate principal amount of 10.0% senior unsecured notes. In 2006, we had outstanding $160 million

52



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 reflects 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 includes a net $0.1 million of realized and unrealized loss on derivative contracts. This includes 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 Internal Revenue Service 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 includes 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 is primarily the result of significant amounts of tax-exempt interest income.

Year Ended December 31, 2006, Compared with Year Ended December 31, 2005

        Total gallons shipped in 2006 were 695.8 million gallons, versus 529.8 million gallons shipped in 2005, an increase of 166.0 million gallons or 31.3%. The increase/(decrease) in gallons by source was as follows:

 
  For the Year Ended December 31,
 
(In thousands, except for percentages)
  2006
  2005
  Increase/
(Decrease)

  % Increase/
(Decrease)

 
Equity production   132,957   138,119   (5,162 ) (3.7 )%
Marketing alliance purchases   492,973   340,589   152,384   44.7 %
Purchase/resale   68,234   68,791   (557 ) (0.8 )%
Decrease/(increase) in inventory   1,620   (17,663 ) 19,283   N.M. *
   
 
 
 
 
Total   695,784   529,836   165,948   31.3 %
   
 
 
 
 

*
N.M.—not meaningful

        Net sales in 2006 increased 70.2% from 2005. Net sales were $1.6 billion in 2006 versus $0.9 billion in 2005. Overall, the increase in net sales was the result of the increase in the average sales price of ethanol and an increase in gallons sold. The average gross selling price of ethanol in 2006 was $2.18 per gallon, up from the $1.63 received in 2005. The increase in ethanol prices was mostly the result of increased ethanol demand caused by the phase-out of MTBE as an oxygenate and from an increase in the RFS, as well as from increases in discretionary blending. Increased demand caused the price of ethanol to increase in the first half of 2006. Ethanol prices in the second quarter reached new highs, and began to fall significantly during the third quarter as a result of Brazilian imports. Ethanol prices regained strength in the fourth quarter as the Brazilian imports were consumed into the marketplace and demand again exceeded supply.

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        Co-product revenue for 2006 totaled $54.7 million, a decrease of $5.7 million or 9.4%, from the 2005 total of $60.4 million. Co-product revenue in 2006 was affected by lower average realized prices, and decreased co-product production due to maintenance. In 2006, we sold 927.2 thousand tons, versus 946.7 thousand tons in 2005. Co-product revenues, as a percentage of corn costs, were 44.7% during 2006, versus 55.9% in 2005. Co-product returns, as a percentage of corn costs, decreased in 2006 as compared to 2005 as the result of increases in the price of corn outpacing the increase in co-product pricing.

        Cost of goods sold for the year ended December 31, 2006 was $1.5 billion, compared to $0.9 billion for the year ended December 31, 2005, an increase of $0.6 billion or 72.2%. This increase was the result of higher costs for purchased ethanol and from increased production costs. Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from our marketing alliance partners, the cost of purchasing ethanol and bio-diesel from other producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers.

        Purchased ethanol in 2006 totaled $1.1 billion, versus approximately $596.4 million in 2005. The increase in purchased ethanol resulted from an increase in the number of gallons of ethanol purchased, along with an increase in the cost per gallon of ethanol purchased. In 2006, we purchased 561.2 million gallons of ethanol at an average cost of $2.06 per gallon as compared to 409.4 million gallons of ethanol at an average cost of $1.52 in 2005.

        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 and amortization. Corn costs in 2006 totaled $122.4 million or $2.41 per bushel, versus $108.0 million, or $2.08 per bushel in 2005. The increase in corn costs was principally the result of a perceived increased demand by the marketplace as a result of expected new ethanol production facilities being built.

        Conversion costs for 2006 increased to $87.2 million from $77.1 million for 2005. The total dollars spent on conversion costs increased year over year principally as a result of higher costs due to the maintenance required at our Illinois wet mill facility and our Nebraska facility in the second quarter of 2006, along with production issues incurred at our Aurora facility in the second and third quarters of 2006, and from the results of severe weather which disrupted production at both the Illinois wet mill and the Aurora facilities in early December 2006. Conversion costs were also affected in 2006 by stock-based compensation expense, higher enzyme and denaturant costs, and from one-time start-up costs related to the new Pekin dry mill. The conversion cost per gallon increased year over year to $0.66 per gallon in 2006 versus $0.56 per gallon in 2005. Our facilities for 2006 ran at approximately 89% of their capacity.

        Depreciation in 2006 totaled $3.7 million, versus $2.3 million in 2005. Motor fuel taxes were $13.6 million in 2006 versus $6.3 million in 2005. The cost of motor fuel taxes are recovered through billings to customers.

        Freight/logistics costs in 2006 increased to $101.7 million, or approximately $0.15 per gallon, from $58.0 million, or $0.11 per gallon in 2005. 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 the result of higher transportation expenses, fuel surcharges and from the expansion of our distribution system footprint.

        The average cost of inventory was $1.91 at the end of 2006 as compared to $1.50 at the end of 2005 reflecting the sharp rise in ethanol pricing during 2006 using our weighted average FIFO approach to calculating inventory. The economic impact of selling gallons that were previously held in

54



inventory at the end of 2005 during a period of significantly rising prices was a reduction to cost of goods sold of $10.3 million.

        SG&A expenses were $28.3 million in 2006, compared to $22.5 million in 2005. SG&A expenses increased as a result of expensing stock-based compensation in accordance with SFAS 123R, increased costs related to being a public company, and the acceleration of vesting periods of certain stock-based compensation arrangements. Stock-based compensation expense in 2006 totaled $6.5 million, versus $1.9 million in 2005.

        Other operating income of $3.4 million included 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. The remainder represented dividends received from our cost method investments in marketing alliance partners, and in payments received from various governmental agencies for ethanol production.

        Interest income in 2006 was $4.7 million, versus $2.2 million in 2005. The increase in interest income is the result of a combination of a higher level of investable funds due to cash received from our initial public offering and better operating results, along with increased short-term investment rates due to increases in interest rates in general.

        Interest expense in 2006 was $9.3 million, as compared to $16.5 million in 2005. Interest expense declined in 2006 principally as a result of the repurchase of our outstanding bonds primarily in July 2006, along with interest capitalized as a result of the construction of our Pekin dry mill facility and lower usage of our secured revolving credit facility. Interest expense in 2006 was also affected by the impact of year over year increases in variable interest rates.

        The minority interest for the year ended December 31, 2006 was a $4.6 million charge to income compared to $2.4 million charge to income for the year ended December 31, 2005. This increase reflected the higher operating results of our Nebraska subsidiary in the year ended December 31, 2006.

        Other non-operating income for 2006 included $3.7 million of mark to market gains on corn futures contracts, versus mark to market gains of $1.8 million in 2005. Other non-operating income consisted of realized or unrealized gains or losses on commodity derivative instruments and mark to market adjustments on an interest rate cap agreement.

        Loss on early extinguishment of debt totaled $14.6 million in 2006. The loss was related to the repurchase of all $160 million aggregate principal amount of our floating rate senior secured notes (including premiums), and from the write-off of deferred financing fees related to the notes as well as our amended and restated secured revolving credit facility.

        Tax expense for 2006 was $31.7 million, or approximately 36.6%, versus $18.8 million, or 36.9%, in 2005. Our effective tax rate was affected by a lower estimated state tax rate in 2006 which more accurately reflected state income tax rates being incurred.

Trends and Factors that May Affect Future Operating Results

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 benefited the ethanol industry. In December 2007, the Energy Independence and Security Act of 2007 was passed which contained a new increased RFS, which requires fuel refiners and importers to use a certain minimum amount of renewable fuels (including ethanol) which will rise to 36 billion gallons by

55



2022. Ethanol benefits from an excise tax credit of $0.51 per ethanol gallon. This excise tax credit provides incentives for blenders and refiners to blend ethanol with gasoline.

Supply and Demand

        Ethanol demand in the U.S. in 2007 exceeded production. U.S production of 6.5 billion gallons in 2007 was slightly less than 2007 consumption of 6.8 billion gallons. The shortfall in 2007 was filled by imports from other countries, principally Brazil. At the end of 2007, U.S. production capacity was 7.5 billion gallons annually. According to the RFA, another 5.8 billion gallons of production capacity was under construction at year-end.

        It is expected that annual ethanol production capacity in the U.S. will total in excess of 12 billion gallons annually by the end of 2008. This additional capacity may cause supply to exceed demand. If additional demand for ethanol is not created, through either additions to discretionary blending (through increased penetration rates in areas that blend ethanol today or through the establishment of new markets where little to no ethanol is blended today), or through additional governmental mandates at either the federal or state level, the excess supply may cause ethanol prices to decrease, 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 a result of this new perceived demand. 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 reliant hybrid varieties of corn.

Natural Gas Prices

        Natural gas is an important input in our ethanol and co-product production process. We use natural gas 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 2007, and could again increase significantly as a result of actual or perceived shortages in supply. Our current natural gas usage is approximately 308,000 MMBtus per month.

Expansion

        We have identified opportunities to increase our equity production capacity through the development of new production facilities and are continually exploring acquisition opportunities. We are currently building 113 million gallon annualized capacity ethanol production facilities at both Mt. Vernon, Indiana and Aurora, Nebraska, which we expect to begin ramping up ethanol production in the first quarter of 2009. In addition, we are obligated to add an additional 113 million gallons of capacity through a phase II expansion in Mt. Vernon, Indiana, and would be subject to material penalties if we do not. We also intend to add an additional 113 million gallons of capacity through a phase II expansion at Aurora, Nebraska, along with potentially expanding our existing Pekin, Illinois campus. The timing of these expansions will be based upon, among other factors, market conditions and the availability of financing on attractive terms. We anticipate that the aggregate capital expenditures to build our phase I expansion at each of Mt. Vernon and Aurora will be approximately

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$250 million per plant, which includes approximately $15 million of additional infrastructure at each plant to facilitate the construction of the phase II expansion. We have not yet entered into agreements for any of our additional expansions. The cost to build these additional expansions will depend on market conditions at the time construction is commenced and may be higher or lower than the cost of the phase I expansions at Mt. Vernon and Aurora. There can be no assurance that we can raise additional funds to complete these projects.

        We may be subject to material penalties if we do not timely complete phase I of the Aurora Expansion or either phase 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. If we 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 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 March 1, 2009 and substantial completion of phase II (an additional 110 million gallons of capacity) by January 1, 2011, subject in the case of the 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 alternations, (ii) without terminating the lease, require us 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. In addition, under the design build agreements for the initial 113 million gallon capacity expansion at each of Mt Vernon and Aurora, we have the ability to delay construction by up to 180 days. If we do so, we will be responsible for certain increased costs and foregone profit of the contractor (potentially including an early completion bonus). If we were to delay construction beyond 180 days the contractor would be entitled to treat the delay as a termination by us for convenience and we would be responsible for certain costs and expenses of the contractor in connection with such termination as well as a termination fee of 1% of the total EPC contract sum.

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Liquidity and Capital Resources

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

(In thousands)
  December 31,
2007

  December 31,
2006

Cash and cash equivalents   $ 17,171   $ 29,791
Short-term investments   $ 211,500   $ 98,925
Working capital   $ 303,377   $ 203,247
Total debt   $ 300,000    
Current ratio     3.90     3.44

Overview and Outlook

        At December 31, 2007, we had invested $211.5 million in taxable ARS which we classified as current assets. We consider these securities as available for sale. The ARS held by the Company are private placement securities with long-term stated maturities for which the interest rates are reset through a Dutch auction every 28 days. The auctions have historically provided a liquid market for these securities as investors historically could readily sell their investments at auction. With the liquidity issues experienced in global credit and capital markets, the ARS held by the Company have experienced multiple failed auctions, beginning on February 8, 2008, as the amount of securities submitted for sale has exceeded the amount of purchase orders.

        Prior to December 31, 2007, we began to exit our position in these securities and continued to do so subsequent to December 31, 2007. As of February 21, 2008, we had successfully liquidated $84.3 million of these securities, thereby leaving us with $127.2 million invested in ARS as of February 21. We incurred a pre-tax loss of approximately $1.5 million in connection with these liquidations. Our remaining ARS consist of various tranches of notes issued by two issuers, College Loan Corporation Trust I and NextStudent Master Trust I. All of these securities continue to carry AAA/Aaa ratings, have not experienced any payment defaults and are backed by student loans which carry guarantees as provided for under the Federal Family Education Loan Program of the U.S. Department of Education. Nonetheless, if uncertainties in the credit and capital markets continue, these markets deteriorate further or there are any ratings downgrades on any ARS we hold, we may be required to recognize impairments and/or reclassify these investments from short-term to long-term investments.

        In addition, these securities may not provide the liquidity to us as we need it, as it could take until the final maturity of the underlying notes (up to 35 years) to realize our investments' recorded value. Currently, there is a very limited market for any of these securities and further liquidations at this time, if possible, would likely be at a significant discount. Accordingly, we do not currently intend to attempt to liquidate any more of these securities until market conditions improve or our liquidity needs require us to do so. Cash and cash equivalents as of December 31, 2007 was $17.2 million. Successful ARS liquidations completed in 2008 generated $82.8 million. At December 31, 2007, we also had availability under our secured revolving credit facility of $122.6 million. Our total estimated remaining expenditures needed to complete our two new facilities at December 31, 2007 are estimated to be between $295 million and $305 million approximately evenly spent over the balance of the construction period through Q1'09.

        On February 27, 2008, Moody's Investors Service ("Moody's") moved our speculative grade liquidity rating down to SGL-3 from SGL-1 with an outlook of negative. Moody's downgrade in the speculative grade liquidity rating to SGL-3 followed our disclosure of potential liquidity issues with our ARS. According to Moody's, the SGL-3 liquidity rating reflects the uncertainty about our future profitability (given current commodity prices) and our liquidity as we spend heavily on new plant construction.

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        On October 26, 2006, Aventine's Board of Directors approved a common stock share buyback program of up to $50 million. Under the repurchase program, the Company may buy back shares from time to time on the open market. The program has no minimum share repurchase amounts, and there is no fixed time period under which any share repurchases must take place. This share repurchase program is not expected to impact the Company's previously announced expansion plans. From program inception through year end 2007, the Company has repurchased a total of 369,615 shares of its common stock, including 248,315 shares in the fourth quarter of 2007. The amount remaining under the authorization to repurchase stock is approximately $45.9 million. The amounts the Company may repurchase under this program in the future may be affected by cash required to complete current facility expansion, as well as cash provided by operations.

        We expect to need additional liquidity in addition to our current cash balances, amounts available under our secured revolving credit facility and anticipated cash flow from operations, in order to be able to satisfy existing anticipated working capital needs, debt service obligations, non-expansion related capital expenditures and other anticipated cash requirements for 2008. After utilization of available resources, should we not be able to liquidate a substantial portion of the remaining portfolio of these ARS securities on a timely basis and on acceptable terms, or the commodity spread continues to decline to levels where it becomes unprofitable to produce and sell ethanol, we will have to either attempt to raise additional funds or slow down the construction of our new facilities, or both. In addition, delays in the construction of our new facilities could expose us to material penalties.

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 2007, cash and short-term investments increased by $100.0 million. Cash and short-term investments as of December 31, 2007 and 2006 were $228.7 million and $128.7 million, respectively. The increase in cash and short-term investments is principally the result of cash received from $300 million aggregate principal amount of senior unsecured 10% fixed rate notes, net of fees, along with cash provided by operations, offset by expenditures related to our plant expansions.

        Cash provided by operations.    Net cash provided by operating activities in 2007 was $47.4 million, as compared to $55.8 million for 2006. The decrease in net cash provided by operating activities is primarily the result of a more difficult operating environment caused by a decline in the commodity spread due to significantly higher corn prices and lower realized average ethanol price per gallon sold in 2007 as compared to 2006.

        Cash available under our credit facility.    In March 2007, we established a new five 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, can be increased to $300 million. 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.

        We had no borrowings outstanding under our secured revolving credit facility at December 31, 2007, 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.

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Uses of Liquidity

        Our principal uses of liquidity are capital expenditures, payments related to our outstanding debt and our credit facility, and the repurchase of shares of our common stock.

        Capital expenditures.    Capital expenditures for the expansion of our facilities totaled $211.7 million in 2007 and $64.6 million in 2006, excluding $7.3 million of capitalized interest for 2007. We expect to spend between $295 million and $305 million, exclusive of any capitalized interest, on capital expansion projects in 2008.

        In 2007, other capital expenditures (excluding expenditures made for capacity expansions) totaled $16.2 million versus $11.9 million in 2006. Other capital expenditures include asset replacement, environmental and safety compliance, and cost reduction and productivity improvement items. Our capital spending plan for 2008, excluding any expenditures for facility additions or expansion, is forecasted to be between $20 million and $25 million.

        Payments related to our outstanding debt and credit facility.    In 2007, we made interest payments on our $300 million senior secured 10% fixed rate notes totaling $15.3 million, versus payments on our then outstanding $160 million senior secured floating rate notes of $11.2 million in 2006. In 2006, we also paid $168.9 million (including premiums) to repurchase all $160 million aggregate principal amount of our then outstanding senior secured floating rate notes. The increase in interest payments from 2006 to 2007 results primarily from the greater levels of debt outstanding and the higher fixed interest rate of the $300 million bond issue.

        Repurchase of shares of 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, 2007. 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 12 and 13 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)   $ 16,300,866   $ 1,654,247   $ 3,254,804   $ 3,254,804   $ 8,137,011
Principal payments on 10% senior unsecured notes due 2017     300,000                 300,000
Interest on 10% senior unsecured notes due 2017     285,000     30,000     60,000     60,000     135,000
Commitments for capital expenditures     270,631     270,631            
Operating leases—railcars     160,080     15,733     40,386     36,758     67,203
Corn     54,945     53,310     1,635        
Corn and gasoline hedge contracts     49,192     47,681     1,511        
Utility supply agreements     47,476     2,462     9,502     7,685     27,827
Operating leases—terminal leases     35,840     12,953     12,462     6,390     4,035
Coal     29,348     14,674     14,674        
Purchased bio-diesel     28,900     19,080     9,820        
Operating leases—barges     14,309     7,090     7,219        
Denaturant     8,367     8,367            
Mt. Vernon lease payments     6,991     371     742     743     5,135
Other     5,025     870     1,571     888     1,696
IT services     3,938     666     839     695     1,738
Natural gas     3,702     3,702            
Electricity     2,266     2,266            
   
 
 
 
 
Total contractual obligations   $ 17,606,876   $ 2,144,103   $ 3,415,165   $ 3,367,963   $ 8,679,645
   
 
 
 
 

(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 $1.91. 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.

Secured Revolving Credit Facility

        Our liquidity facility consists of a five-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, can be increased up to $300 million. Our secured revolving credit facility includes 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.

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        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, 2007, the amount of property, plant and equipment which was eligible for inclusion in the calculation of the borrowing base was $48.2 million.

        Borrowings generally bear interest, at our option, at the following rates (i) the Eurodollar 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 every three months. In addition, fees and expenses are payable based on unused borrowing availability (0.25% to .375% per annum, depending on the average availability), outstanding letters of credit (1.375% to 1.875% fee, depending on the average availability) and administrative and legal costs.

        Availability under our secured revolving credit facility is subject to customary conditions, including 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 fixed charge coverage ratio of EBITDA (as defined under the agreement) less non-financed capital expenditures and taxes to fixed charges (scheduled investments of principal, interest expense, and dividends and certain other payments) of 1.1 to 1.

        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. Obligations under the secured revolving credit facility may be accelerated upon the occurrence of an event of default.

        We had no borrowings outstanding under our secured revolving credit facility at December 31, 2007, 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.

Environmental 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

62



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 CERCLA 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 contamination or such third party claims. We have not accrued any amounts for environmental matters as of December 31, 2007. 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.

        Our air emissions are subject to the federal Clean Air Act, the federal Clean Air Act Amendments of 1990 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 affect 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. 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 VOC emissions and other air emissions from many U.S. ethanol plants, including our Illinois and Nebraska facilities. The matter 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 costs we incurred for this 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. In February 2008, we received an indemnification payment from the former owner of our Nebraska facility relating to the cost of

63



installing environmental controls at that facility related to an April 2005 consent decree with state authorities.

        We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the EPA's final National Emissions Standard for Hazardous Air Pollutants, or NESHAP, under the federal Clean Air Act 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 certain of our boilers and process heaters. 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 boilers and process heaters.

        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, in 2007, Illinois and four other Midwestern States entered into the Midwestern Greenhouse Gas Reduction Accord, which program 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 require other costly carbon dioxide emissions reductions.

        See Note 14 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, 2007 and 2006 were $3.76 and $2.41 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 price decrease in the market price of corn between the time this price is fixed and the time the corn is delivered. In order to reduce our market exposure to price

64



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 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 all derivative positions are netted together, and the net fair value amount is recorded in either prepaid expenses or accounts payable 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)
  2007
  2006
 
Realized and unrealized net gain included in earnings   $ 2.9   $ 0.1  
 
  December 31,
 

(In millions)

 

2007

 

2006


 
Net bushels sold     3.9     8.0  
Aggregate notional value of derivatives outstanding   $ 16.5   $ 28.0  
Period through which derivative positions currently exist     December 2009     December 2009  
Unrealized loss on fair value of derivatives   $ 1.5   $ 3.1  
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value   $ (1.8 ) $ (3.2 )

        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 all derivative positions are netted together, and the net fair value amount is recorded in either prepaid expenses or accounts payable 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)
  2007
  2006
 
Realized and unrealized net gain included in earnings   $ 4.6   $ 2.8  
 
  December 31,
 

(In millions)

 

2007

 

2006


 
Net bushels bought     5.3     2.0  
Aggregate notional value of derivatives outstanding   $ 22.4   $ 5.1  
Period through which derivative positions currently exist     July 2008     March 2007  
Unrealized gain on fair value of derivatives   $ 2.6   $ 2.8  
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value   $ (2.5 ) $ (0.8 )

        We are also subject to market risk with respect to ethanol pricing. Our ethanol sales are priced using contracts that can either be fixed; 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, 2007, we had fixed contracts to sell approximately 62.8 million gallons of ethanol at an average fixed price of $1.78 per gallon through December 2008. We have elected to account for these transactions as normal sales under SFAS 133, and accordingly, have not marked these transactions to market.

65


        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, 2007, we had sold forward approximately 72.7 million gallons of ethanol using wholesale gasoline as an index plus a fixed spread that averaged a negative $0.45 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 all derivative positions are netted together, and the net fair value amount is recorded in either prepaid expenses or accounts payable 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)
  2007
  2006
Realized and unrealized net loss included in earnings   $ 8.7   $
 
  December 31,

(In millions)

 

2007

 

2006

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 eight year period from 1999 through December 2007, 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 2003. Natural gas costs comprised 18.7% and 13.8%, respectively, of our total conversion costs for the years ended December 31, 2007 and 2006.

        We did not have any exchange traded futures contracts for the purchase or sale of natural gas as of December 31, 2007. Based upon our annual average estimated natural gas usage and the December 31, 2007 year end price of natural gas of $8.03 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, 2007 was $274.5 million, versus a carrying value of $300.0 million. We did not have any debt outstanding at December 31, 2006. A 1% increase from prevailing interest rates would result in a decrease in fair value of this debt by approximately $23.0 million as of December 31, 2007. 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 10.93% as of December 31, 2007. Generally, changes in the market value of our fixed-rate debt do not affect us, unless we repurchase the debt in the open market.

66


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.

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, 2007, 2006 and 2005.    F-1
Consolidated Balance Sheets—December 31, 2007 and 2006.    F-2
Consolidated Statements of Stockholders' Equity (Deficit)—For the years ended December 31, 2007, 2006 and 2005.    F-3
Consolidated Statements of Cash Flows—For the years ended December 31, 2007, 2006 and 2005.    F-4
Notes to Consolidated Financial Statements.    F-5
Report of Independent Registered Public Accounting Firm.    F-36
Report of Independent Registered Public Accounting Firm.    F-37

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, and our Chief Financial Officer, Ajay Sabherwal, 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, Messrs. Miller and Sabherwal have 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

67



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 Messrs. Miller and Sabherwal, 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 Messrs. Miller and Sabherwal, there has been no change in our internal control over financial reporting during the fourth quarter of 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 Messrs. Miller and Sabherwal, assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. 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, 2007, our internal control over financial reporting was effective.

        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 2008 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 2008 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 2008 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 2008 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 2008 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 2008 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 2008 Annual Meeting of Stockholders.

69



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, 2007, 2006, and 2005.

      Consolidated Balance Sheets—December 31, 2007 and 2006.

      Consolidated Statements of Stockholders' Equity (Deficit)—For the years ended December 31, 2007, 2006, and 2005.

      Consolidated Statements of Cash Flows—For the years ended December 31, 2007, 2006, and 2005.

      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-38 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

  3.1(1)   Amended and Restated Certificate of Incorporation of Aventine Renewable Energy Holdings, Inc.

 

3.2(1)

 

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

 

4.1(1)

 

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(1)

 

Registration Rights Agreement dated as of December 23, 2005 by and between Aventine Renewable Energy Holdings, Inc. and Friedman, Billings, Ramsey & Co., Inc.

 

4.3

 

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

70



 

10.1.2

 

Second Amendment to Mt Vernon Lease Agreement, dated as of October 18, 2007

 

10.1.3

 

Third Amendment to Mt Vernon Lease Agreement, dated as of January 26, 2008

 

10.2(1)

 

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

 

10.3

 

Design-Builder Agreement between Fagen, Inc. and Aventine Renewable Energy Holdings, Inc. dated as of September 9, 2005**

 

10.4(4)

 

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

 

10.5(4)

 

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

 

10.6(5)

 

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**

 

10.7(5)

 

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**

 

10.8(5)

 

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

 

10.9(5)

 

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

 

10.10*

 

Non-Employee Director Compensation Schedule

 

10.11(6)*

 

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

 

10.12(6)*

 

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

 

10.13(6)*

 

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

 

10.14(6)*

 

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

 

10.15

 

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)

 

10.16

 

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)

 

10.17

 

Registration Rights Agreement, dated as of March 27, 2007, among the Company, the subsidiary guarantors named therein and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 10.1 of Aventine's Current Report on Form 8-K filed on April 2, 2007)

71



 

10.18*

 

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)

 

10.19(2)*

 

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

 

10.20(2)*

 

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

 

10.21

 

Settlement and Release Agreement, dated as of February 27, 2008, by and among the Company, The Williams Companies, Inc. and Williams Energy Services, LLC

 

21

 

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

(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.

72



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 5th day of March 2008.

    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      
Ronald H. Miller
  President and Chief Executive Officer and Director (Principal Executive Officer)   March 5, 2008

By:

 

/s/  
AJAY SABHERWAL      
Ajay Sabherwal

 

Chief Financial Officer (Principal Financial Officer)

 

March 5, 2008

By:

 

/s/  
WILLIAM J. BRENNAN      
William J. Brennan

 

Chief Compliance and Accounting Officer (Principal Accounting Officer)

 

March 5, 2008

By:

 

/s/  
BOBBY LATHAM      
Bobby Latham

 

Non-Executive Chairman of the Board and Director

 

March 5, 2008

By:

 

/s/  
LEIGH J. ABRAMSON      
Leigh J. Abramson

 

Director

 

March 5, 2008

By:

 

/s/  
RICHARD A. DERBES      
Richard A. Derbes

 

Director

 

March 5, 2008

By:

 

/s/  
FAROKH S. HAKIMI      
Farokh S. Hakimi

 

Director

 

March 5, 2008

By:

 

/s/  
MICHAEL C. HOFFMAN      
Michael C. Hoffman

 

Director

 

March 5, 2008

By:

 

/s/  
WAYNE D. KUHN      
Wayne D. Kuhn

 

Director

 

March 5, 2008

By:

 

/s/  
ARNOLD M. NEMIROW      
Arnold M. Nemirow

 

Director

 

March 5, 2008

73



Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Statements of Operations

 
  Year ended December 31,
 
(In thousands except per share amounts)
  2007
  2006
  2005
 
Net sales   $ 1,571,607   $ 1,592,420   $ 935,468  
Cost of goods sold     1,497,807     1,460,806     848,053  
   
 
 
 
Gross profit     73,800     131,614     87,415  
Selling, general and administrative expenses     36,367     28,328     22,500  
Other income     (1,113 )   (3,389 )   (989 )
   
 
 
 
Operating income     38,546     106,675     65,904  
Other income (expense):                    
  Interest expense     (16,240 )   (9,348 )   (16,510 )
  Interest income     12,432     4,771     2,218  
  Loss on early extinguishment of debt         (14,598 )    
  Other non-operating income (expense)     (78 )   3,654     1,781  
  Minority interest     (1,338 )   (4,568 )   (2,404 )
   
 
 
 
Income before income taxes     33,322     86,586     50,989  
Income tax expense/(benefit)     (477 )   31,685     18,807  
   
 
 
 
Net income   $ 33,799   $ 54,901   $ 32,182  
   
 
 
 

Income per common share—basic

 

$

0.81

 

$

1.43

 

$

0.93

 
Basic weighted-average number of shares     41,886     38,411     34,686  
Income per common share—diluted   $ 0.80   $ 1.39   $ 0.89  
Diluted weighted-average number of common and common equivalent shares     42,351     39,639     36,052  
   
 
 
 

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

F-1



Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Balance Sheets

 
  December 31,
 
(In thousands except share and per share amounts)
  2007
  2006
 
Assets              
Current assets:              
  Cash and equivalents   $ 17,171   $ 29,791  
  Short-term investments     211,500     98,925  
  Accounts receivable, net of allowance for doubtful accounts of $48 in 2007 and $25 in 2006     73,058     79,729  
  Inventories     81,488     67,051  
  Income taxes receivable     11,962     6,446  
  Prepaid expenses and other     12,816     4,549  
   
 
 
Total current assets     407,995     286,491  

Property, plant and equipment, net

 

 

111,867

 

 

40,962

 
Construction in process     226,410     74,683  
Deferred tax assets     1,196      
Investment in marketing alliance partners     6,000     6,000  
Other assets     8,717      
   
 
 
Total assets   $ 762,185   $ 408,136  
   
 
 

Liabilities and Stockholders' Equity

 

 

 

 

 

 

 
Current liabilities:              
  Accounts payable   $ 91,871   $ 77,442  
  Accrued interest     7,500      
  Accrued liabilities     3,625     3,679  
  Other current liabilities     1,622     2,123  
   
 
 
Total current liabilities     104,618     83,244  
Senior unsecured 10% fixed rate notes     300,000      
Deferred tax liabilities         6,104  
Minority interest     9,832     10,221  
Other long-term liabilities     3,864     4,404  
   
 
 
Total liabilities     418,314     103,973  

Stockholders' equity:

 

 

 

 

 

 

 
    Common stock, par value $0.001 per share; 185,000,000 shares authorized, 41,734,223 and 41,782,276 shares outstanding as of December 31, 2007 and 2006, respectively, net of 21,548,640 and 21,229,025 shares held in treasury as of December 31, 2007 and 2006, respectively     42     42  
    Preferred stock, 50,000,000 shares authorized, no shares issued or outstanding          
    Additional paid-in capital     279,218     274,307  
    Retained earnings     64,935     30,888  
    Accumulated other comprehensive loss, net     (324 )   (1,074 )
   
 
 
Total stockholders' equity     343,871     304,163  
   
 
 
Total liabilities and stockholders' equity   $ 762,185   $ 408,136  
   
 
 

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

F-2


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Statements of Stockholders' Equity (Deficit)

 
   
  Common Stock
   
   
  Accumulated
Other
Comprehensive
(Loss)

   
 
 
  Treasury
Shares

  Additional
Paid-In
Capital

  Retained
Earnings

  Total
Stockholders'
Equity/(Deficit)

 
(In thousands except number of shares)
  Shares
  Amount
 
Balance at December 31, 2004     34,684,253   $   $   $ (56,195 ) $ (386 ) $ (56,581 )
  Reclassification of additional paid-in capital to par value of common stock             35     (35 )                
  Proceeds from common stock offering       21,179,025     21     256,033             256,054  
  Repurchase of common stock for the treasury   21,179,025   (21,179,025 )   (21 )   (256,033 )           (256,054 )
  Tax benefit of stock option exercises               2,122             2,122  
  Stock option exercises       461,000         173             173  
  Stock-based compensation               1,931             1,931  
  Comprehensive income:                                        
    Net income                   32,182         32,182  
    Minimum pension liability, net of tax of $320                       (481 )   (481 )
                                   
 
  Total comprehensive income                           31,701  
   
 
 
 
 
 
 
 
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 of 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  
   
 
 
 
 
 
 
 

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

F-3



Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

 
  Year ended December 31,
 
(In thousands)
  2007
  2006
  2005
 
Operating Activities                    
Net income   $ 33,799   $ 54,901   $ 32,182  
Adjustments to reconcile net income to net cash provided by operating activities:                    
  Depreciation and amortization     13,265     4,628     3,623  
  Loss on early extinguishment of debt         14,598      
  Deferred income taxes     (6,664 )   (1,177 )   2,589  
  Gain on disposal of fixed assets     (3 )   (110 )   (3 )
  Minority interest     1,338     4,568     2,404  
  Stock-based compensation expense     7,204     6,478     1,931  
  Mark to market of derivative contracts         839     (898 )
  Changes in operating assets and liabilities:                    
    Accounts receivable, net     6,671     (33,104 )   (16,580 )
    Inventories     (14,437 )   (12,400 )   (29,813 )
    Proceeds from marketing commission buydown             3,000  
    Prepaid expenses and other     (14,217 )   (5,315 )   1,137  
    Accounts payable     14,429     25,914     26,716  
    Accrued liabilities, including pension and postretirement benefits     6,016     (4,058 )   417  
   
 
 
 
Net cash provided by operating activities     47,401     55,762     26,705  

Investing Activities

 

 

 

 

 

 

 

 

 

 
Additions to property, plant and equipment, net     (235,211 )   (76,499 )   (20,675 )
Purchases of short-term securities     (690,948 )   (98,925 )      
Redemptions of short-term securities     578,373          
Investment in marketing alliance partners         (5,000 )    
Increase in restricted cash for plant expansion         (1,257 )   (1,971 )
Release of restricted cash related to repayment of senior notes         29,762      
Use of restricted cash for plant expansion         31,857     4,109  
Proceeds from the sale of fixed asset     5     131     3  
   
 
 
 
Net cash used for investing activities     (347,781 )   (119,931 )   (18,534 )

Financing Activities

 

 

 

 

 

 

 

 

 

 
Proceeds from issuance of senior unsecured fixed rate notes     300,000          
Financing fees and expenses paid     (8,220 )        
Net borrowings from (repayments of) revolving credit facilities         (1,514 )   (11,277 )
Repayment of senior secured floating rate notes and related premium         (168,899 )    
Distribution to minority shareholders     (1,727 )   (3,022 )   (2,590 )
Proceeds from issuance of common stock, net         260,890     256,054  
Repurchase of common stock     (2,983 )   (1,152 )   (256,054 )
Tax benefit of stock option exercises     180     3,687     2,122  
Proceeds from stock option exercises     510     220     173  
   
 
 
 
Net cash provided by (used for) financing activities     287,760     90,210     (11,572 )
   
 
 
 
Net increase (decrease) in cash and equivalents     (12,620 )   26,041     (3,401 )
Cash and equivalents at beginning of year     29,791     3,750     7,151  
   
 
 
 
Cash and equivalents at end of year   $ 17,171   $ 29,791   $ 3,750  
   
 
 
 

Supplemental disclosure of cash flow:

 

 

 

 

 

 

 

 

 

 
Interest paid   $ 15,333   $ 11,162   $ 15,046  
Income taxes paid   $ 11,033   $ 33,161   $ 16,913  

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

F-4



Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

1.    Nature of Operations

        Aventine Renewable Energy Holdings, Inc. and Subsidiaries (the "Company," "Aventine," "we," "our," or "us") is a leading producer and marketer of ethanol both in terms of gallons produced and gallons sold. Through our own production facilities, marketing alliances with other ethanol producers and our purchase/resale operations, we market and distribute ethanol to many of the leading energy companies in the U.S. We have a comprehensive national distribution network utilizing a leased railcar and barge fleet and a terminal network at critical points on the nation's transportation grid where our ethanol is blended with our customers' gasoline. We are also a marketer and distributor of bio-diesel. 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.

        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.

        On December 23, 2005, the Company completed an equity offering (the "144a equity offering") of 21,179,025 shares of common stock pursuant to Rule 144a of the Securities Act. All of the net proceeds of the 144a equity offering were used to repurchase an equal number of shares from existing shareholders. The repurchase of shares is reflected as a treasury stock transaction in the accompanying consolidated financial statements. The shares sold were subject to a registration rights agreement where the Company agreed, at its expense, to use reasonable efforts to file a shelf registration statement registering for resale the shares sold in the offering. The registration statement related to these shares became effective on July 25, 2006. In connection with the offering, the Company authorized a 805.47131 for 1 stock split. All share data presented has been adjusted to reflect the stock split.

        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.

2.    Summary of Critical 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.

        Aventine owns 78.4% of Nebraska Energy, LLC. The remaining 21.6% of Nebraska Energy, LLC is owned by Nebraska Energy Cooperative. The Company has included in its consolidated financial statements all of the revenues and expenses of Nebraska Energy, LLC and the interest therein of the Nebraska Energy Cooperative is reflected as minority interest.

F-5


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

2.    Summary of Critical Accounting Policies (Continued)

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 biofuels.

Revenue Recognition Policy

        Revenue is generally recognized when title to products transfer to an unaffiliated customer. This generally occurs after the product has been offloaded at the customers' site, the sales price is fixed and determinable, and collection is reasonably assured. Sales are made under normal terms and usually do not require collateral. The Company also markets ethanol for its marketing alliance partners and ethanol and bio-diesel from unaffiliated producers. Sales revenue on non-Aventine produced gallons are generally recorded on a gross basis in the accompanying statements of operations, because the Company takes title to and is the primary obligor in the sales arrangement with customers. Purchase and sale transactions of biofuels entered into with the same counterparty in transactions negotiated in contemplation of one another are recorded on a net basis.

        Shipping and handling and motor fuel tax costs invoiced to the customer are included in sales, and the related expenses are included in cost of goods sold.

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, 2007, we had invested $211.5 million in taxable auction rate securities ("ARS") which we classified as current assets. We consider these securities as available for sale. The ARS held by the Company are private placement securities with long-term stated maturities for which the interest rates are reset through a Dutch auction every 28 days. The auctions have historically provided a liquid market for these securities as investors historically could readily sell their investments at auction. With the liquidity issues experienced in global credit and capital markets, the ARS held by the Company have experienced multiple failed auctions, beginning on February 8, 2008, as the amount of securities submitted for sale has exceeded the amount of purchase orders.

        Prior to December 31, 2007, we began to exit our position in these securities and continued to do so subsequent to December 31, 2007. As of February 21, 2008, we had successfully liquidated $84.3 million of these securities, thereby leaving us with $127.2 million invested in ARS as of February 21. We incurred a pre-tax loss of approximately $1.5 million in connection with these liquidations. Our remaining ARS consist of various tranches of notes issued by two issuers, College Loan Corporation Trust I and NextStudent Master Trust I. All of these securities continue to carry AAA/Aaa ratings, have not experienced any payment defaults and are backed by student loans which

F-6


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

2.    Summary of Critical Accounting Policies (Continued)


carry guarantees as provided for under the Federal Family Education Loan Program of the U.S. Department of Education. Nonetheless, if uncertainties in the credit and capital markets continue, these markets deteriorate further or there are any ratings downgrades on any ARS we hold, we may be required to recognize impairments and/or reclassify these investments from short-term to long-term investments.

        In addition, these securities may not provide the liquidity to us as we need it, as it could take until the final maturity of the underlying notes (up to 35 years) to realize our investments' recorded value. Currently, there is a very limited market for any of these securities and further liquidations at this time, if possible, would likely be at a significant discount. Accordingly, we do not currently intend to attempt to liquidate any more of these securities until market conditions improve or our liquidity needs require us to do so.

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 67% and 75% of our consolidated sales revenue for the years ended December 31, 2007 and 2006, respectively. In 2007, our three largest customers accounted for approximately 15%, 11% and 10% of our consolidated revenue and in 2006, our two largest customers account for 18% and 12% 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 current assets over the purchase price was allocated to reduce the carrying values of the non-current assets, including property, plant and equipment.

F-7


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

2.    Summary of Critical Accounting Policies (Continued)

Impairment of Long-Lived Assets

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

        The Company has made investments in four marketing alliance partners (each of which is less than 8% of total ownership at December 31, 2007). The total investment made by the Company after May 31, 2003 of $6 million is accounted for using the cost method. Investments made by the predecessor company in two marketing alliance partners prior to May 30, 2003 were written down to zero as part of the purchase price allocation upon the acquisition of the Company by MSCP. In conjunction with our investment in Ace Ethanol, LLC and Indiana BioEnergy, LLC, we are entitled to a seat on each of these companies Board of Directors for as long as we maintain an ownership interest.

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 is recognizing the related revenue over the life of the agreement which extends through August 2012. The unrecognized balance at December 31, 2007 is $2.0 million. The portion to be recognized over the next 12 months of $0.4 million is included in other current liabilities. The remainder is included in other long-term liabilities on the consolidated balance sheets.

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.

        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.

F-8


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

2.    Summary of Critical Accounting Policies (Continued)

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, inventories, prepaid pension, postretirement benefit obligations, and certain other accrued liabilities are the primary sources of these temporary differences. Deferred income tax also includes tax credit 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.

        In July 2006, the FASB issued FIN 48. This interpretation clarified the accounting for uncertainty in income taxes recognized in the financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure.

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.

        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 may be exempted 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's contracts that meet the requirements of normal are documented as normal and exempted from the accounting and reporting requirements of SFAS 133.

F-9


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

2.    Summary of Critical Accounting Policies (Continued)

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 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.

        The following table summarizes fair value information for our financial instruments:

(In thousands)
  2007
Carrying value

  2007
Fair value

  2006
Carrying value

  2006
Fair value

 
Assets/(liabilities)                          
Cash and cash equivalents   $ 17,171   $ 17,171   $ 29,791   $ 29,791  
Short-term investments     211,500     211,500     98,925     98,925  
Commodity margin deposits     4,013     4,013     1,503     1,503  
Senior unsecured fixed rate notes     (300,000 )   (274,500 )        
Investment in marketing alliance partners, at cost     6,000       (a)   6,000       (a)

(a)
These investments are in non-publicly traded companies for which it is not practical to estimate fair value.

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 $0.3 million, $0.2 million and $0.1 million for the years ended 2007, 2006 and 2005, respectively.

Recent Accounting Pronouncements

        In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 ("SFAS 157"), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company does

F-10


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

2.    Summary of Critical Accounting Policies (Continued)


not expect the adoption of SFAS 157 to have a significant impact on our consolidated financial position or results of operations.

        In February 2007, the FASB issued 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. SFAS No. 159 permits a company to choose to measure many financial instruments and other items at fair value that are not currently required to be measured at fair value. The objective is to improve financial reporting by providing a company with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. A company shall report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. SFAS No. 159 will be effective for fiscal years that begin after November 15, 2007. We do not believe that the adoption of SFAS No. 159 will have a significant impact on our consolidated financial position or results of operations.

        In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141-R ("SFAS 141R"), Business Combinations, which revised Statement of Financial Accounting Standards No. 141, Business Combinations ("SFAS 141"). This pronouncement is effective for business combinations for fiscal years beginning after December 15, 2008. Under SFAS 141, organizations utilized the announcement date as the measurement date for the purchase price of the acquired entity. SFAS 141R requires measurement at the date the acquirer obtains control of the acquiree, generally referred to as the acquisition date. SFAS 141R will have a significant impact on the accounting for transaction costs, restructuring costs as well as the initial recognition of contingent assets and liabilities assumed during a business combination. Under SFAS 141R, adjustments to the acquired entity's deferred tax assets and uncertain tax position balances occurring outside the measurement period are recorded as a component of the income tax expense, rather than goodwill. As the provisions of SFAS 141R are applied prospectively, the impact cannot be determined until the transactions occur.

        In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160 ("SFAS 160"), Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51. SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Among other requirements, SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is to be reported as a separate component of equity in the consolidated financial statements. SFAS also requires consolidated net income to include the amounts attributable to both the parent and the noncontrolling interest and to disclose those amounts on the face of the consolidated statement of income. SFAS 160 must be applied prospectively for fiscal years, and is effective for fiscal years beginning after December 15, 2008, except for the presentation and disclosure requirements, which will be applied retrospectively for all periods presented.

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

F-11


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

3.    Related Party Transactions (Continued)


Metalmark remains and an independent entity owned by those individuals and continues to manage the applicable MSCP funds on a sub-advisory basis.

        At the time of the MSCP funds' acquisition of the Company, one of the MSCP funds entered into consulting agreements with each of its three directors. Under these agreements, each of these directors agreed to serve as one of the Company's directors and to provide consulting services to the Company, as reasonably requested by such MSCP fund. The agreements had two one-year terms, which would automatically renew, unless either party provided 30 days' written notice prior to the end of the term. On April 30, 2004, the MSCP fund assigned its rights and obligations under these consulting agreements to us. The Company was then obligated to pay the directors under these agreements. Except for payments pursuant to the consulting agreements, the directors did not receive any additional compensation for their services as a director. A payment of $0.3 million was made under these agreements in 2005. The consulting agreements were terminated as of December 31, 2005, and were superseded by a non-employee director compensation program. 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 conjunction with the $160 million senior secured note offering, we paid an advisory fee of $0.4 million to an affiliate of the MSCP funds. In conjunction with the December 2005 144a equity offering, the MSCP funds agreed to reimburse us for $1.5 million of the expenses incurred as a result of the 144a equity offering. The remaining amount of $0.4 million was paid by the Company and is included in selling, general, and administrative expenses. After giving effect to the 144a equity offering, the MSCP funds owned approximately 39.6% of the Company's outstanding stock. Upon completion of our initial public offering, the MSCP funds owned approximately 28.3% of the Company.

        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 investments in marketing alliances all of which are less than 8.0% of total ownership. Total purchases from these plants aggregated $240.9 million, $228.2 million and $137.8 million, for the years ended December 31, 2007, 2006 and 2005, respectively. These transactions were recorded at market prices and under normal commercial terms. As of December 31, 2007, we had recorded in accounts payable approximately $10.1 million owed to the marketing alliance partners in which 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.

F-12


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

4.    Inventories

        Inventories are as follows:

 
  December 31,
(In thousands)
  2007
  2006
Finished products   $ 73,530   $ 61,775
Work-in-process     2,035     1,106
Raw materials     2,757     2,070
Supplies     3,166     2,100
   
 
Totals   $ 81,488   $ 67,051
   
 

5.    Prepaid Expenses and Other

        Prepaid expenses and other are as follows at December 31:

(In thousands)
  2007
  2006
Prepaid motor fuel taxes   $ 5,061   $
Fair value of derivative instruments     4,013     1,503
Prepaid insurance     1,107     1,280
Prepaid ethanol     1,050    
Deferred income taxes current     854     1,064
Other prepaid expenses     731     702
   
 
Totals   $ 12,816   $ 4,549
   
 

6.    Property, Plant and Equipment

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

(In thousands)
  2007
  2006
 
Land and improvements   $ 1,659   $ 1,659  
Building and improvements     5,300     1,510  
Machinery and equipment     122,788     43,242  
Storage tanks     3,108     2,965  
Furniture and fixtures     25     25  
Less accumulated depreciation     (21,013 )   (8,439 )
   
 
 
Totals   $ 111,867   $ 40,962  
   
 
 

Construction-in-progress

 

 

226,410

 

 

74,683

 
   
 
 

        Depreciation expense in 2007, 2006 and 2005 was $12.6 million, $3.7 million and $2.3 million, respectively.

F-13


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

7.    Other Assets

        Other assets at December 31 are as follows:

(In thousands)
  2007
  2006
Deferred debt issuance costs   $ 7,533   $
Funded status of pension plan     1,184    
   
 
Totals   $ 8,717   $
   
 

        Deferred debt issuance costs are subject to amortization. Remaining deferred debt issuance costs of $6.7 million related to our 10% senior unsecured notes will be amortized utilizing a method which approximates the effective interest method over the remaining life of 10 years, resulting in amortization expense of $0.7 million yearly. Remaining deferred debt issuance costs of $0.8 million related to our secured revolving credit facility will be amortized utilizing a method which approximates the effective interest method over the five year remaining life, resulting in amortization expense of $0.2 million in each of the next four succeeding years beginning in 2008.

8.    Other Current Liabilities

        Other current liabilities are as follows at December 31:

(In thousands)
  2007
  2006
Accrued sales taxes   $ 184   $ 821
Deferred income taxes     379     429
Accrued property taxes     578     418
Current portion of unearned commission     424     425
Other accrued operating expenses     57     30
   
 
Totals   $ 1,622   $ 2,123
   
 

9.    Secured Revolving Credit Facility

        Our liquidity facility consists of a five 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, can be increased up to $300 million. Our secured revolving credit facility includes 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.

        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, 2007, the amount of property, plant and equipment which was eligible for inclusion in the calculation of the borrowing base was $48.2 million.

        Borrowings generally bear interest, at our option, at the following rates (i) the Eurodollar 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

F-14


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

9.    Secured Revolving Credit Facility (Continued)


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 every three months. In addition, fees and expenses are payable based on unused borrowing availability (0.25% to 0.375% per annum, depending on the average availability), outstanding letters of credit (1.375% to 1.875% fee, depending on the average availability) 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 fixed charge coverage ratio of EBITDA (as defined under the agreement) less non-financed capital expenditures and taxes to fixed charges (scheduled investments of principal, interest expense, and dividend and certain other payments) of 1.1 to 1.

        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. Obligations under the secured revolving credit facility may be accelerated upon the occurrence of an event of default.

        We had no borrowings outstanding under our secured revolving credit facility at December 31, 2007, 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.

10.    Senior Notes

        In March 2007, we issued $300 million aggregate principal amount of senior unsecured 10% fixed-rate notes due April 2017 ("Notes"). Our 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.

F-15


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

10.    Senior Notes (Continued)

        The Notes have interest payments due semi-annually on April 1 and October 1 of each year, and 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 100% 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 unsecured senior notes, with terms identical to the Notes.

        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.

11.    Interest Expense

        The following table summarizes interest expense:

 
  Year Ended December 31,
 
(in thousands)
  2007
  2006
  2005
 
Interest expense—bonds and other   $ 22,833   $ 10,230   $ 16,021  
Interest expense—revolving credit facility     703     317     560  
Capitalized interest     (7,296 )   (1,199 )   (71 )
   
 
 
 
Total interest expense   $ 16,240   $ 9,348   $ 16,510  
   
 
 
 

12.    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 $1.0 million in 2007, $1.3 million in 2006, and $1.2 million in 2005.

F-16


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

12.    Retirement and Pension Plans (Continued)

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:

 
  2007
  2006
 
Equity securities   57 % 44 %
Debt securities   31   36  
Guaranteed Investment Contracts   0   16  
Cash and equivalents   12   4  
   
 
 
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, 2007, the annual measurement date, our Retirement Plan had a projected accumulated benefit obligation of $7.8 million and the fair value of the plan assets was $9.0 million. In accordance with SFAS 158, we recognized the overfunded status of the plan by recording an accrued pension asset of $1.2 million. The offsetting amount charged to accumulated other comprehensive loss adjusts the total in other comprehensive loss to $0.5 million pre-tax, which is the amount of the net unrecognized actuarial loss and unrecognized prior service cost.

F-17


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

12.    Retirement and Pension Plans (Continued)

        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)
  2007
  2006
 
Funded/(Unfunded) status   $ 1,184   $ (152 )

Amounts recognized in

 

 

 

 

 

 

 
  Other assets     1,184      
  Other long-term liabilities         152  
  Deferred taxes     208     608  
  Accumulated other comprehensive loss:              
    Unamortized prior service cost     532     350  
    Unamortized net actuarial loss/(gain)     (5 )   600  

        The amount of unamortized prior service costs that will be recognized as a component of net periodic pension cost in 2008 is expected to be $42 thousand. There is no expected amortization in 2008 of unamortized net actuarial gains.

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

 
  2007
  2006
 
Discount rate   6.50 % 5.75 %

        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)
  2007
  2006
  2005
 
Service cost   $ 351   $ 285   $ 277  
Interest cost     497     430     416  
Expected return on plan assets     (720 )   (512 )   (488 )
Amortization of net actuarial loss     25     47     2  
Amortization of prior service cost     42          
   
 
 
 
Net periodic pension cost   $ 195   $ 250   $ 207  
   
 
 
 

        The amortization of our net actuarial loss in 2007 of $25 thousand is the amortization of total unrecognized losses as of January 1, 2007 that exceeds 10% of our projected benefit obligation, approximately $1.2 million, and is being amortized over the expected average remaining years of service of the plan participants which is approximately 14 years.

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

 
  2007
  2006
  2005
 
Discount rate   5.75 % 5.50 % 6.00 %
Expected long-term rate of return on plan assets   8.50 % 8.50 % 8.50 %

F-18


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

12.    Retirement and Pension Plans (Continued)

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

(In thousands)
  2007
  2006
 
Benefit obligation at the beginning of the year   $ 8,607   $ 8,000  
Service costs     351     285  
Interest costs     497     430  
Actuarial gain     (1,275 )   (340 )
Benefits paid     (365 )   (342 )
Amendments         574  
   
 
 
Benefit obligation at the end of the year   $ 7,815   $ 8,607  
   
 
 

        At December 31, 2007 and 2006, the projected benefit obligation and the accumulated benefit obligation are equal.

        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 actuarial gain for the year ended December 31, 2006 results primarily from the increase in the discount rate used in the calculation of the benefit obligation to 5.75% from 5.50%.

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

(In thousands)
  2007
  2006
 
Fair value of plan assets at the beginning of the year   $ 8,455   $ 6,212  
Employer contributions     500     2,000  
Actual return on plan assets     408     585  
Benefits paid     (364 )   (342 )
   
 
 
Fair value of plan assets at the end of the year   $ 8,999   $ 8,455  
   
 
 

        In 2008, we anticipate making contributions totaling $0.9 million.

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

(in thousands)
   
2008   $ 412
2009     446
2010     469
2011     484
2012     547
2013–2017     2,949

13.    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

F-19


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

13.    Postretirement Benefit Obligation (Continued)


under the plan reduces at age 65 from a defined benefit to a defined dollar cap based upon years of service.

        On December 31, 2007, the annual measurement date, our Postretirement Plan had an accumulated benefit obligation of $2.3 million, which is approximately the same as the accumulated benefit obligation at December 31, 2006. 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)
  2007
  2006
 
Unfunded status   $ (2,339 ) $ (2,275 )
Amounts recognized in:              
  Other long-term liabilities     (2,339 )   2,275  
  Deferred taxes     4     79  
  Accumulated other comprehensive loss:              
    Unamortized net actuarial loss     10     123  

        There is no expected amortization of the unamortized net actuarial loss in 2008.

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

(In thousands)
  2007
  2006
  2005
Service cost   $ 151   $ 153   $ 188
Interest cost     135     122     157
Recognized net actuarial gain         10     52
   
 
 
Net periodic postretirement benefit cost   $ 286   $ 285   $ 397
   
 
 

F-20


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

13.    Postretirement Benefit Obligation (Continued)

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

(In thousands)
  2007
  2006
 
Benefit obligation at the beginning of the year   $ 2,275   $ 3,201  
Service cost     151     153  
Interest cost     135     122  
Actuarial (gain)     (192 )   (1,172 )
Benefits paid     (30 )   (29 )
   
 
 
Benefit obligation at the end of the year   $ 2,339   $ 2,275  
   
 
 

        The weighted-average discount rate used to determine net periodic postretirement benefit cost was 6.0% at December 31, 2007 and 5.5% at December 31, 2006.

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

(in thousands)
   
2008   $ 29
2009     33
2010     41
2011     43
2012     71
2013–2017     777

        For purposes of determining the cost and obligation for pre-Medicare postretirement medical benefits, a 12.7% annual rate of increase in the per capita cost of covered benefits (i.e., health care trend rate) was assumed for the plan in 2007, declining to a rate of 5.74% in 2014. 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   $ 20   $ (16 )
Effect on postretirement benefit obligation   $ 180   $ (150 )

14.    Environmental Remediation and Contingencies

        We are subject to various stringent federal, state and local environmental laws and 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. We cannot provide assurance that we have been, are or will be at all times in complete compliance with these laws, regulations or permits or that we have had or currently have all permits required for our operations. In addition, environmental laws and regulations (and interpretations thereof) change over time, and any such changes, more vigorous enforcement policies or

F-21


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

14.    Environmental Remediation and Contingencies (Continued)


the discovery of currently unknown conditions may require substantial additional environmental expenditures.

        Federal and state environmental authorities have been investigating alleged excess volatile organic compound emissions and other air emissions from many U.S. ethanol plants, including our Illinois and Nebraska facilities. The matter relating to our Illinois wet mill facility is still pending, and we could be required to install costly additional air pollution control equipment or take other measures to control air pollutant emissions at that 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 an indemnification payment from the former owner of our Nebraska facility relating to the cost of installing environmental controls at that facility related to an April 2005 consent decree with state authorities.

        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. 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 of 1980, or "CERCLA," 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 contamination or such third party claims. We have not accrued any amounts for environmental matters as of December 31, 2007.

        We are not involved in any legal proceedings that we believe could reasonably have a material adverse effect upon our business, operating results or financial condition.

15.    Income Taxes

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

(In thousands)
  2007
  2006
  2005
Current expense   5,749   32,754   16,218
Deferred expense/(benefit)   (6,226 ) (1,069 ) 2,589
   
 
 
Total income tax expense/(benefit)   (477 ) 31,685   18,807
   
 
 

        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)
  2007
  %
  2006
  %
  2005
  %
 
Income tax provision at federal statutory rate   $ 11,663   35.0   $ 30,305   35.0   $ 17,846   35.0  
Increase/(decrease) in taxes resulting from:                                
  State and local taxes, net of federal benefit     947   2.8     3,314   3.8     2,209   4.3  
  FIN 48 recognition of previously unrecognized uncertain tax positions     (8,089 ) (24.3 )   2,319   2.7     2,225   4.4  
  Tax exempt interest income     (2,592 ) (7.8 )   (667 ) (0.8 )      
  Release of valuation allowances     (1,563 ) (4.7 )   (2,023 ) (2.3 )   (2,051 ) (4.0 )
  Other     (843 ) (2.4 )   (1,563 ) (1.8 )   (1,422 ) (2.8 )
   
 
 
 
 
 
 
Income tax expense/(benefit)   $ (477 ) (1.4 ) $ 31,685   36.6   $ 18,807   36.9  
   
 
 
 
 
 
 

F-22


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

15.    Income Taxes (Continued)

        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)
  2007
  2006
 
Current deferred tax asset   $ 854   $ 1,064  
   
 
 

Current deferred tax liability

 

$

379

 

$

429

 
   
 
 

Long-term deferred tax liabilities:

 

 

 

 

 

 

 
Basis of property, plant and equipment   $ 3,858   $ 447  
Production credits         753  
Partnership investment     2,349     1,386  
Contingency reserve         8,899  
   
 
 
Long-term deferred tax liability   $ 6,207   $ 11,485  
   
 
 

Long-term deferred tax assets:

 

 

 

 

 

 

 
Investment in marketing alliances   $ 1,419     2,439  
Benefit obligations     241     260  
Accumulated other comprehensive income     212     687  
Other     1,952     2,706  
Stock-based compensation     4,782     2,826  
   
 
 
Long-term deferred tax assets     8,606     8,918  
Valuation allowance     (1,203 )   (3,537 )
   
 
 
Net long-term deferred tax assets     7,403     5,381  
   
 
 

Net long-term deferred tax asset/(liability)

 

$

1,196

 

$

(6,104

)
   
 
 

        At December 31, 2007, the Company has recorded a valuation allowance of $1.2 million on its deferred tax assets that management believes may not be realized due to potential limitations imposed by Section 382 of the Internal Revenue Code. The deferred tax assets include the excess tax basis in marketing alliances over the corresponding book basis and other deductible temporary differences.

        As a result of our acquisition by The Williams Companies, Inc. on May 30, 2003, we established deferred tax assets associated with the excess tax basis over book basis in such assets. We determined, after weighing all available evidence, that a portion of the deferred tax asset would not be realized due to potential limitations imposed by Section 382 of the Internal Revenue Code. We established an initial valuation allowance against certain deferred tax assets related to the tax basis in fixed assets and goodwill. We have been reducing the valuation allowance and increasing our income tax contingency reserve as deductions are taken on our federal income tax return associated with fixed assets and goodwill.

        We adopted the provisions of FIN 48 on January 1, 2007. As a result of the adoption, we recognized a $0.7 million decrease in our reserves for uncertain tax positions and a $0.5 million increase in accrued interest on uncertain tax positions, resulting in a net $0.2 million increase in retained earnings. We also reclassified $8.1 million between deferred income taxes and other long-term

F-23


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

15.    Income Taxes (Continued)


liabilities to conform to the balance sheet presentation requirements of FIN 48. As of January 1, 2007, we had $8.5 million of uncertain tax benefits.

        An audit of our federal income tax returns covering fiscal years 2004 and 2005 was completed in September 2007. As a result, the Company was able to finalize positions relating to certain tax matters which previously required liability recognition under FIN 48. The Company recognized in the third quarter of 2007 a previously unrecorded favorable tax benefit of $9.6 million, which includes its previously recorded liability for uncertain tax benefits, the related interest and the release of previously established code section 382 valuation allowances. As of December 31, 2007, the Company has no uncertain tax positions outstanding.

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

Balance at January 1, 2007   $ 8,527  
Additions based on tax positions related to the current year     999  
Reductions based on tax positions taken in the current year     (999 )
Reductions for tax positions related to prior years     (6,212 )
Settlements     (392 )
Reductions for lapse of statute of limitations     (1,923 )
   
 
Balance at December 31, 2007   $  
   
 

        We included 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 January 1, 2007 was $0.5 million, net of the deferred tax benefit, and was previously included in other long-term liabilities. As of December 31, 2007, because we had no uncertain tax positions outstanding, we also had no liability for accrued interest on unrecognized tax benefits.

        The Company files a federal and various state income tax returns. Our federal income tax returns for 2006 and 2007 are open for examination under the federal statute of limitations. We file in numerous state jurisdictions with varying statutes of limitations open from 2003 to 2007 depending on each jurisdiction's unique statute of limitation.

        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 recognized $0.3 million and $0.7 million in tax benefits related to the qualified domestic production credit for the years ended December 31, 2007 and 2006, respectively.

F-24


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

16.    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, 2004   $ (386 )
  Minimum pension liability adjustment, net of income tax benefit of $320     (481 )
   
 
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 )
   
 

17.    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, 2007, there were no Series A participating preferred stock rights that had been exercised.

18.    Stock-Based Compensation Plans

        As of December 31, 2007, 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

F-25


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

18.    Stock-Based Compensation Plans (Continued)


payment awards made to employees and directors, including stock options and non-vested stock, based on their fair values at the time of grant.

        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.

        In conjunction with an equity offering and related stock split of 805.47131 to 1 shares completed in December 2005, all then existing option awards were adjusted to reflect the stock split as permitted by the Plan. The modification resulted in an increase in the number of options outstanding in a ratio of 805.47131 to 1. The exercise price of the options was also adjusted downward by this same 805.47131 to 1 ratio. The fair value of the awards immediately after the adjustment did not exceed the fair value of the awards immediately before the adjustment. Therefore, no additional compensation expense was recognized as a result of the modification.

        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"), which was previously used in determining stock-based compensation cost using the minimum value method as outlined in Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, using the modified prospective method as permitted under the provisions of Statement of Accounting Standards No. 148 ("SFAS 148"), Accounting for Stock-Based Compensation—Transition and Disclosure (hereinafter called "SFAS 123"). 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 are estimated using a 3% forfeiture rate. 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

F-26


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

18.    Stock-Based Compensation Plans (Continued)


shares are stock units that will be converted to common shares, to the extent earned, at the end of a three-year performance cycle. The first performance cycle began on January 1, 2007, and will end on December 31, 2009. 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. 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. Under FAS 123R, an accounting estimate of the number of these shares that are expected to vest has been made and are being expensed utilizing the grant-date fair value of the shares from the date of grant through the end of the performance cycle period. Any future changes to the estimate will be reflected in stock-based compensation expense in the period the estimate change is made.

        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. Pre-tax stock-based compensation expense for the year ended December 31, 2006 was approximately $6.5 million, of which $0.3 million was charged to cost of goods sold and $6.2 million was charged to selling, general and administrative expense. This expense reduced earnings per share by $0.10 per basic and diluted share for the year ended December 31, 2006. The Company recognized a tax benefit on its consolidated statement of income from stock-based compensation expense in the amount of $2.8 million and $2.4 million, respectively, for the 12 month periods ended December 31, 2007 and 2006. The Company recorded pre-tax stock-based compensation expense for the year ended December 31, 2007 and 2006 as follows:

(in millions)
  Year Ended December 31, 2007
  Year Ended December 31, 2006
Stock-based compensation expense:            
  Non-qualified options   $ 6.5   $ 6.4
  Restricted stock   $ 0.2   $ 0.1
  Restricted stock units   $ 0.1   $
  Long-term incentive plan   $ 0.4   $

        The minimum value method as permitted by SFAS 123 was utilized in calculating stock-based compensation expense for 2005. The Company recorded pre-tax stock-based compensation expense for the year ended December 31, 2005 as follows:

 
  Year Ended December 31,
(in millions)
  2005
Stock-based compensation expense:      
  Non-qualified options   $ 1.9
  Restricted stock   $
  Restricted stock units   $
  Long-term incentive plan   $

F-27


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

18.    Stock-Based Compensation Plans (Continued)

        Prior to the adoption of SFAS 123(R), the Company presented any tax benefits of deductions resulting from the exercise of stock options within operating cash flows in the consolidated statements of cash flows. SFAS 123(R) requires tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options to be classified and reported as both an operating cash outflow and a financing cash inflow upon adoption of SFAS 123(R).

        As of December 31, 2007, the Company had not yet recognized compensation expense on the following non-vested awards:

(in millions)
  Non-recognized Compensation
  Remaining Recognition Period (years)
Non-qualified options   $ 17.8   2.2
Restricted stock     1.0   1.9
Restricted stock units     0.1   0.4
Long-term incentive plan     1.2   2.0
   
 
Total   $ 20.1   2.2
   
 

        The determination of the fair value of the stock option awards, using the Option Pricing Model for the years ended December 31, 2007 and 2006 and the minimum value method for the year ended December 31, 2005, incorporated the assumptions in the following table for stock options granted:

 
  December 31,
 
 
  2007
  2006
  2005
 
Expected stock price volatility     58 %   58 %   0.01 %
Expected life (in years)     6.5     6.5     5  
Risk-free interest rate     4.76 %   4.92 %   4.0 %
Expected dividend yield     0 %   0 %   0 %
Weighted average fair value   $ 9.76   $ 14.52   $ 11.69  

F-28


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

18.    Stock-Based Compensation Plans (Continued)

        The following table summarizes stock options outstanding and changes during the years ended December 31, 2007, 2006 and 2005:

 
  Shares
(in thousands)

  Weighted-
Average
Exercise
Price

  Weighted-
Average
Remaining
Life
(years)

  Aggregate
Intrinsic
Value
(in thousands)

Options outstanding—December 31, 2004   2,194   $ 0.53          
Granted   1,269     3.80          
Exercised   (461 )   0.23          
Cancelled or expired   (83 )   0.23          
   
 
 
 
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   $ 16,384
Options exercisable—December 31, 2007   1,234   $ 3.77   6.5   $ 11,090
   
 
 
 

        The range of exercise prices of the exercisable options and outstanding options at December 31, 2007 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   666   1,006   5.5
$2.36–$2.92   338   744   7.4
$4.35   96   616   7.8
$15.26–$17.29     480   9.4
$22.15–$22.50   126   630   8.3
$43.00   8   40   8.5
   
 
 
Totals   1,234   3,516   7.4
   
 
 

        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. 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.

F-29


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

18.    Stock-Based Compensation Plans (Continued)

        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, 2007 and 2006 is summarized below. There was no restricted stock outstanding at December 31, 2005.

 
  Shares
(in thousands)

  Weighted-
Average
Grant Date
Fair Value
per Award

Unvested Restricted stock awards—January 1, 2006     $
Granted   8.1     27.92
Vested      
Cancelled or expired      
   
 
Restricted stock awards—December 31, 2006   8.1   $ 27.92
   
 
Granted   70.5     15.40
Vested      
Cancelled or expired      
   
 
Restricted stock awards—December 31, 2007   78.6   $ 16.69
   
 

        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 year ended December 31, 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      
   
 
Restricted stock unit awards—December 31, 2007   18.0   $ 15.85
   
 

F-30


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

19.    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 $220.0 million as of December 31, 2007 and are payable as follows:

(in millions)
   
2008   $ 36.8
2009   $ 34.7
2010   $ 27.3
2011   $ 23.4
2012   $ 20.8
Thereafter   $ 77.0

        Rental expense for operating leases was $25.4 million in 2007, $17.7 million in 2006 and $10.8 million in 2005.

        At December 31, 2007, we have commitments of $270.6 million for the construction of two new dry mill facilities in Aurora, Nebraska and Mt. Vernon, Indiana. We had no other commitments for capital expenditures at December 31, 2007.

        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. At December 31, 2007, Aventine had agreements with 13 producing alliance partners. The contracts range from one year to as long as Aventine retains an investment in the alliance facility. In addition, we have entered into new marketing agreements with both existing and new marketing alliance partners for the marketing of additional gallons that are either under construction or planned.

        At December 31, 2007, we have committed to purchase approximately 484,000 MMBtus of natural gas at a weighted average fixed price of $7.65 during 2008.

        At December 31, 2007, we had futures contracts to purchase approximately 245,000 tons of coal at a weighted average fixed price of $59.89 per ton.

        At December 31, 2007, we also had commitments to purchase approximately 13.4 million bushels of corn through December 2009, at an average price of $4.10 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.

F-31


Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

20.    Earnings Per Share

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

(In thousands, except per share amounts)
  2007
  2006
  2005
Income available to common shares   $ 33,799   $ 54,901   $ 32,182
Basic weighted-average common shares     41,886     38,411     34,686
Dilutive stock options     465     1,228     1,366