UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

[Mark One]

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

for the fiscal year ended December 31, 2011.

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

One Lincoln Centre
5400 LBJ Freeway, Suite 450
Dallas, Texas	75240
(Address of principal executive offices)	(Zip Code)

(214) 451-6750

(Registrant’s Telephone Number, including Area Code)

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

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

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

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

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

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

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

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

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2011 was approximately $35,300,556 based upon the closing price of the Common Stock reported for such date on the OTC Bulletin Board.

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

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

Class	Outstanding as of February 10, 2012
Common Stock, $0.001 par value	8,392,341 Shares

FORM 10-K

YEAR ENDED DECEMBER 31, 2011

TABLE OF CONTENTS

		Page No.
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
Item 3.	Legal Proceedings	32
Item 4.	Mine Safety Disclosures	33
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	65
Item 9A.	Controls and Procedures	65
Item 9B.	Other Information	66
PART III
Item 10.	Directors and Executive Officers of the Registrant and Corporate Governance	67
Item 11.	Executive Compensation	72
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	82
Item 13.	Certain Relationships and Related Transactions and Director Independence	85
Item 14.	Principal Accounting Fees and Services	86
PART IV
Item 15.	Exhibits and Financial Statement Schedules	87

PART I

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

Item 1.  Business

General

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

Emergence from Reorganization Proceedings and Related Events

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

1

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

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

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

Industry Overview

Ethanol is marketed across the U.S. as a gasoline blend component that serves as a clean air additive, an octane enhancer and a renewable fuel resource. It is blended with gasoline (i) as an oxygenate to help meet fuel emission standards, (ii) to improve gasoline performance by increasing octane levels and (iii) to extend fuel supplies.

The U.S. ethanol industry has experienced rapid growth, increasing from 1.5 billion gallons of production in 1999 to approximately 13.9 billion gallons produced in 2011.  According to the Renewable Fuels Association (the “RFA”), the use of the 13.9 billion gallons of ethanol displaced the need for 485 million barrels of oil to refine into gasoline.  The RFA also reports that the U.S. fuel ethanol industry has approximately 209 operating plants and approximately 14.9 billion gallons of annual production capacity (including idled capacity) for 2012.

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

·Mandated usage of renewable fuels. The growth in ethanol usage has been supported by regulatory requirements dictating the use of renewable fuels, including ethanol. The Energy Independence and Security Act of 2007 (the “EISA”), confirmed by the U.S. Environmental Protection Agency’s (the “EPA”) regulations on the Renewable Fuel Standards (the “RFS”) issued on March 26, 2010 (“RFS2”), sets the mandate for corn based ethanol from 10.5 billion gallons in 2009 to 15.0 billion gallons in 2015.  The total renewable fuel requirement increases from 11.1 billion gallons in 2009 to 36.0 billion gallons by 2022.

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

2

separate federal and state air emission standards. The refining industry has all but abandoned the use of MTBE, making ethanol the primary clean air oxygenate currently used.

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

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

Ethanol Production Processes

The production of ethanol from corn can be accomplished through one of two distinct processes: wet milling and dry milling.  According to the RFA, approximately 90% of U.S. ethanol production is at dry mill plants. Though the number of dry mill facilities significantly exceeds the number of wet mill facilities, their size is typically smaller.  The principal difference between the two processes is the initial treatment of the grain and the resulting co-products.  The increased production of higher margin co-products in the wet mill process results in a lower ethanol yield.  At a denaturant blend level of 1.96%, a typical wet mill yields approximately 2.74 gallons of ethanol per bushel of corn while a typical dry mill yields approximately 2.81 gallons of fully denatured ethanol per bushel of corn.

Wet Milling

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

Dry Milling

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

3

Business Overview

Today we derive our revenue primarily from the sale of ethanol produced at our plants.  Historically, we have sourced ethanol from the following three sources:

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

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

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

We market and sell ethanol without regard to the source of origination.  Gallons of ethanol marketed and distributed were as follows:

	Year Ended December 31,	Percentage		Year Ended December 31,		Percentage		Year Ended December 31,	Percentage
	2011	of Total		2010		of Total		2009	of Total
	(In millions, except for percentages)
Equity production	248.7	96.6	%	186.4		101.3	%	197.5	71.2	%
Marketing alliances	—	—		—		—		30.9	11.1	%
Purchase/resale	6.7	2.6	%	1.2		0.7	%	35.5	12.8	%
Decrease/(increase) in inventory	2.1	0.8	%	(3.6	)	(2.0	)%	13.6	4.9	%
Total gallons	257.5	100.0	%	184.0		100.0	%	277.5	100.0	%

Equity Ethanol Production

Our equity production operations generate the substantial majority of our operating income or loss.  We own and operate one of the few coal-fired, corn wet mill plants in the U.S. in Pekin, Illinois, which we refer to as the “Illinois wet mill facility.”  In addition, we own and operate a natural gas-fired corn dry mill plant in Pekin, Illinois which we refer to as the “Illinois dry mill facility.” We refer to our Illinois dry mill and wet mill facilities collectively as our ‘‘Illinois facilities.’’ In addition, we own a natural gas-fired corn dry mill plant in Aurora, Nebraska, which we refer to as the “Nebraska facility.”  During 2010, we built 110 million gallon denatured annualized capacity ethanol production facilities at both Mt. Vernon, Indiana, which we refer to as the “Mt. Vernon facility,” and Aurora, Nebraska, which we refer to as the “Aurora West facility.”  Both the Mt. Vernon facility and Aurora West facility were substantially completed by the end of the fourth quarter of 2010; however, in consideration of the winter months, we delayed start-up activities at the Aurora West facility. Production began at the Mt. Vernon facility in the first quarter of 2011.  Additionally, in August 2010 we acquired a 38 million gallon denatured annualized capacity ethanol production facility in Canton, Illinois, which we refer to as the ‘‘Canton facility.”  We expect the Aurora West and Canton facilities to become operational in 2012, subject to weather conditions, commodity prices, and the availability of working capital.

For the year ended December 31, 2011, our facilities had a combined total ethanol production capacity of approximately 312 million gallons annually with corn processing capacity of approximately 115 million bushels.  For the years ended December 31, 2010 and 2009, our facilities had a combined total ethanol production capacity of approximately 202 million gallons annually with corn processing capacity of approximately 75 million bushels.  When all of our plants are online and operating at capacity, our expected total ethanol production will be at approximately 460 million gallons annually.

Our plants may operate at a capacity which is less than the stated nameplate capacity.  We occasionally experience plant outages (both planned and unplanned), as well as other related productivity issues.  Planned outages are typically for maintenance and average approximately one week per plant each

4

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

Marketing Alliances

Historically, our marketing business was an important component of our business. Marketing alliance partners were third-party producers (including producers in which we may have had a non-controlling interest), who sold their ethanol production to us on an exclusive basis.  Due to severely declining margins and general liquidity stress due to frozen credit markets during 2008, we negotiated termination agreements with our marketing alliance partners and began to primarily focus on sales of our equity production.

Purchase/Resale

Historically, we have also purchased ethanol from unaffiliated third-party producers and marketers on both a spot basis and under contract.  These transactions were driven by our ability to purchase ethanol and then, through our distribution network and customer relationships, resell the ethanol.  The margin from purchase/resale transactions could be volatile and we occasionally incurred losses on these transactions. As discussed above under “Marketing Alliances”, we began to focus on sales of our equity production and reduce our sourcing of ethanol from third parties in late 2008.  Our purchase/resale program was part of this rationalization process.

Products

We generated revenue from the following products:

	Year Ended December 31,		Percentage of Total		Year Ended December 31,		Percentage of Total		Year Ended December 31,		Percentage of Total
	2011		Revenue		2010		Revenue		2009		Revenue
	(In millions, except for percentages)
Ethanol	$	680.2	76.7	%	$	344.9	77.0	%	$	490.3	82.5	%
Co-Products	190.2		21.4	%	88.5		19.7	%	85.4		14.4	%
Bio-Products	17.2		1.9	%	14.9		3.3	%	12.5		2.1	%
Other	—		—		—		—		6.4		1.0	%
Total	$	887.6	100	%	$	448.3	100.	%	$	594.6	100.0	%

Ethanol

Our principal product is fuel-grade ethanol, an alcohol which is derived in the U.S. principally from corn.  Ethanol is sold primarily for blending with gasoline to meet mandates for the required consumption and use of biofuels, as an octane enhancer, as an oxygenate additive for the purpose of meeting fuel emission standards, and as a fuel extender.

By-Products

We generate additional revenue through the sale of by-products, both co-products and bio-products, which result from the ethanol production process.  The volume of by-products we produce varies with the level of our equity production.  Scheduled maintenance, along with other non-scheduled operational difficulties, may affect the volume of by-products produced.  We may also shift the mix of these by-products to increase our revenue.  By-product revenue is driven by both the quantity of by-products produced and the market price received for our by-products, which have historically tracked the price of corn.  For the years ended December 31, 2011, 2010 and 2009, we recaptured approximately 32.3%, 35.2% and 34.1% of our total corn costs, respectively, from the sale of by-products.

5

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

Our Illinois wet mill facility produces co-products, such as corn gluten feed (both wet and dry), corn gluten meal, corn distillers with soluble (“CCDS”), and corn germ.  In addition, the fermentation process yields carbon dioxide.  Our dry mill facilities in Pekin, Illinois, Mt. Vernon, Indiana and Aurora, Nebraska produce co-products such as DDGS, wet distillers grains with soluble and carbon dioxide.  These co-products are sold for various consumer uses into large commodity markets.  Corn gluten feed, corn gluten meal, CCDS and distillers grains are used as animal feed ingredients, corn germ is sold for the extraction of corn oil for human consumption, and carbon dioxide is sold for food-grade use such as beverage carbonation and dry ice.

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

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

Customers

The substantial majority of our customer base has purchased ethanol from us for over six years (including our predecessor companies).  In 2011, 2010 and 2009, our ten largest customers accounted for approximately 85%, 82% and 66%, respectively, of our consolidated ethanol sales volume.

In 2011, Marathon Petroleum Corporation and Buckeye Energy Services LLC (“Buckeye”) accounted for 24.0% and 14.2%, respectively of the Company’s consolidated net sales.  In 2010, Buckeye and BioUrja Trading LLC (“BioUrja”) accounted for 17.0% and 11.0%, respectively of the Company’s consolidated net sales.  In 2009, BioUrja Trading LLC and Exxon Mobil accounted for 10.5% and 11.1%, respectively, of the Company’s consolidated net sales.  No other customers in 2011, 2010 and 2009 represented more than 10% of Aventine’s consolidated net sales.

Pricing and Backlog

Ethanol is generally sold through short-term contracts.  The majority of ethanol sold to customers is based upon index prices.  The price of ethanol has historically moved in relation to the price of wholesale gasoline and the value of the Volumetric Ethanol Excise Tax Credit (the “VEETC”).  However, the price of ethanol over the last three years has been largely driven by supply/demand fundamentals and the price of corn.  As of December 31, 2011, we had contracts for delivery of ethanol totaling 62.0 million gallons through September 30, 2012, of which 3.9 million gallons were based on fixed-price contracts and 58.1 million were at spot prices using Platts and OPIS indices.

Raw Materials and Suppliers

Our principal raw material is #2 yellow corn.  In 2011, 2010 and 2009, we purchased approximately 93.2 million, 71.8 million and 74.2 million bushels of corn, respectively.  We contract for our corn requirements through a variety of sources, including farmers, grain elevators, and cooperatives. Due to our

6

plants being located in or near the Midwestern portion of the U.S., we believe that we have ample access to various corn markets and suppliers. At December 31, 2011, we had 1.0 million bushels of corn inventory stored on-site at our production facilities.

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

Utilities

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

We rely upon third parties for our supply of natural gas which is consumed in the production of ethanol at our Illinois dry mill facility, Mt. Vernon facility and Nebraska facility. The prices for and availability of natural gas are subject to volatile market conditions. These market conditions often are affected by factors beyond our control such as weather conditions, overall economic conditions and foreign and domestic governmental regulation and relations.  We currently use approximately 5.6 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 start-up of our Aurora West and Canton facilities.  We expect the Aurora West and Canton facilities to become operational in 2012, subject to weather conditions, commodity prices, and the availability of working capital.

Employees

During 2011, we hired additional staff for the Canton facility.  At December 31, 2011, we had a total of 348 full-time equivalent employees, compared to 341 as of December 31, 2010. Approximately 45% of our current full-time employees (comprised of the hourly employees at our Illinois facilities) are represented by a union. The unionized employees are covered by a collective bargaining agreement between our subsidiary, Aventine Renewable Energy, Inc., and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industry and Service Workers International Union, Local 7-662 (the “Union”). Our contract with the Union is scheduled to expire on October 31, 2012.

Competitive Strengths

We believe that our competitive strengths include the following:

·Strong Market Position. We are a leading producer and marketer of ethanol in the U.S. based on both gallons of ethanol produced and sold.  For the year ended December 31, 2011, we produced 248.7 million gallons of ethanol and decreased our ethanol inventory by 2.1 million gallons for a total sales volume of 257.5 million gallons, including 6.7 million gallons of ethanol sold from purchase/resale.

·Diversified Supply Base. Our facilities are diversified across geography, fuel source and technology, allowing us to capitalize on multiple opportunities and limit our exposure to any one input. We also generate revenue from multiple sources, including our equity production,and co-products.

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

7

ability to distribute ethanol extensively.

·Low Cost Producer. We believe we are one of the lowest cost producers of ethanol in the U.S. Our Illinois wet mill facility generates 36.2% of its own electricity and its remaining energy needs are met by using lower cost coal, which provides us significant cost savings compared to ethanol facilities that use higher cost natural gas to generate power. In addition, our Illinois wet mill facility, through its wet mill production process, generates higher margin co-products and bio-products, which allowed us to recapture 43.7% of our corn cost in the year ended December 31, 2011, which is a higher percentage than our competitors who employ the dry mill production process. At our Illinois dry mill facility, Mt. Vernon facility and Nebraska facility which employ the dry mill process, we recaptured 25.6%, 25.3% and 24.9% of our total corn costs, respectively, in the year ended December 31, 2011.

·Experienced and Proven Management Team. Our management team of top officers and plant managers has a combined 70 years of experience in the ethanol production industry. Our Chief Executive Officer, John Castle, was previously the Senior Vice President of Operations and Chief Financial Officer of White Energy, Inc., (“White Energy”) an ethanol production company.  Our Chief Financial Officer, Calvin Stewart, was previously the Chief Financial Officer of White Energy.

Competition

We operate in a highly competitive ethanol marketing and production industry.  The top ten producers, of which we are one, accounted for approximately 49.0 %, 46.2%, and 47.9% of total industry capacity for the years ended December 31, 2011, 2010 and 2009, respectively.  All of these producers have annual production capacity exceeding 200 million gallons per year.  The largest ethanol producer’s share of domestic capacity was 12% in both 2011 and 2010, and 11% in 2009.  According to the RFA, the U.S. leads the world in ethanol production with 209 biorefineries in 29 states across the country as of January 2012, with an additional 2 plants either expanding or under construction.

As a result of Valero Energy Corporation’s acquisition of ten ethanol plants during 2009, the second largest U.S. oil refiner is now a top ten producer with annual ethanol production capacity of approximately 1 billion gallons. The remaining producers consist primarily of small capacity producers and farmer cooperatives.

Historically, the world’s ethanol producers have competed primarily on a regional basis.  Imports into the U.S. were generally limited by an import tariff of $0.54 per gallon (other than from Caribbean basin countries which were exempt from this tariff up to specified limits).  This tariff expired on December 31, 2011.  In recent years, we have begun facing competition from foreign producers.  Brazil is the world’s second largest ethanol producer.  Brazil makes ethanol primarily from sugarcane, a process which has historically been lower in cost than producing ethanol from corn.  Several large companies produce ethanol in Brazil.

Business and Growth Strategies

We are pursuing the following business and growth strategies:

·Opportunistically Add Production Capacity to Enhance Operating Cash Flow. We have identified opportunities to increase our equity production capacity through the development of new production facilities. During 2010, we built 110 million gallon denatured annualized capacity ethanol production facilities at both Mt. Vernon, Indiana and Aurora, Nebraska, which were completed by the end of the fourth quarter of 2010.  Additionally, in August 2010, we

8

acquired the Canton facility. After the completion of these projects, our expected ethanol production capacity will be approximately 460 million gallons per year.

·Capitalize on Current and Changing Regulation. Through continued investment in increasing production capacity, we believe we are well positioned to take advantage of the current and changing regulatory environment in our industry.  The original RFS program required 7.5 billion gallons of renewable fuel to be blended into gasoline by 2012. Under the EISA, the RFS program was expanded to increase the volume of renewable fuel required to be blended into transportation fuel from 9.0 billion gallons in 2008 to 36.0 billion gallons by 2022, of which 15.0 billion gallons relates to corn based ethanol.

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

Legislative Drivers and Governmental Regulations

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

·The EISA;

·The federal ethanol tax incentive program;

·Federal tariff on imported ethanol;

·The use of fuel oxygenates; and

·Various state mandates.

The EISA

Enacted into law on December 19, 2007, the EISA significantly increases the volume of renewable fuel required to be blended into transportation fuel from 9.0 billion gallons in 2008 to 36.0 billion gallons by 2022, of which 15.0 billion gallons relates to grain based ethanol. Waiver provisions enable the EPA to reduce the renewable fuel volumetric obligation targets for reasons including severe economic or environmental harm or an inadequate domestic supply of renewable fuels.

The federal ethanol tax incentive program

First passed in 1979, the VEETC program allowed gasoline distributors who blended ethanol with gasoline to receive a federal excise tax credit for each gallon of ethanol they blended. 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 blended. Under the Food, Conservation and Energy Act of 2008, the tax credit was reduced to $0.45 per gallon for 2009 and thereafter. The tax incentives were extended through 2011. The tax incentive was not renewed for 2012 and has now lapsed.  See ‘‘Risk Factors—The use and demand for ethanol and its supply are highly dependent on various federal and state legislation and regulation, and any changes in legislation or regulation could cause the demand for ethanol to decline or its supply to increase, which could have a material adverse effect on our business, results of operation and financial condition.’’

Federal tariff on imported ethanol

In 1980, Congress imposed a tariff on foreign produced ethanol to offset the value of federal tax subsidies. This tariff was designed to protect the benefits of the federal tax subsidies for U.S. farmers. The

9

tariff was originally $0.60 per gallon in addition to a 3.0% ad valorem duty. The tariff was subsequently lowered to $0.54 per gallon with a 2.5% ad valorem duty and was not adjusted completely in direct relative proportion with change in the VEETC. The 2008 Farm Bill extended the $0.54 per gallon tariff on foreign produced ethanol until January 1, 2011, and ultimately the tariff was extended through 2011.  This tariff was not renewed for 2012 and has now lapsed.

Ethanol imports from 24 countries in Central America and the Caribbean Islands were exempt from this tariff under the Caribbean Basin Initiative (the “CBI”) in order to spur economic development in that region. Under the terms of the CBI, member nations could export ethanol into the U.S. up to a total limit of 7% of U.S. production per year (with additional exemptions for ethanol produced from feedstock in the Caribbean region over the 7% limit).  With the lapse of the tariff in December 2011, this could have a negative effect on our industry. In the past, significant imports of ethanol into the U.S. have had a negative effect on ethanol prices. See ‘‘Risk Factors—The use and demand for ethanol and its supply are highly dependent on various federal and state legislation and regulation, and any changes in legislation or regulation could cause the demand for ethanol to decline or its supply to increase, which could have a material adverse effect on our business, results of operation and financial condition.’’

Use of fuel oxygenates

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

State Mandates

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

Patents and Trademarks

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

Environmental and Regulatory Matters

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

10

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 presently own or operate (or properties we formerly owned or operated) and at off-site locations where we arranged for the disposal of hazardous wastes. For instance, over ten years ago, soil and groundwater contamination from fuel oil contamination at a storage site was identified at our Illinois facility. The fuel oil tanks were removed and a portion of the area has been capped, but no remediation has been performed. If any of these sites are subject to investigation and/or remediation requirements, we may incur strict and/or joint and several liability under the Comprehensive Environmental Response, Compensation and Liability Act (or analogous state laws) or other environmental laws which impose strict liability for all or part of the costs of such investigation, remediation, or removal costs and for damages to natural resources whether the contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with applicable laws at the time those actions were taken.  We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties or other impacts of our operations. While costs to address contamination or related third-party claims could be significant, based upon currently available information, we are not aware of any material liability relating to contamination or such third party claims. We have not accrued any amounts for environmental matters as of December 31, 2011. The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

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

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

Federal and state environmental authorities have been investigating alleged excess volatile organic compounds (“VOCS”) emissions and other air emissions from many U.S. ethanol plants, including our

11

Illinois facilities. The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility. If authorities require us to install controls, we would anticipate that costs would be approximately $6.5 million, which would be considerably higher than the approximately $3.4 million we incurred in connection with a similar investigation at our Nebraska facility due to the larger size of the Illinois wet mill facility. As of now, we have not established reserves for possible costs we may incur in connection with this investigation. In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material. With respect to the investigation of our Nebraska facility, we were required to pay a fine of $40,000. Due to the larger capacity of the Illinois facilities, the fine could possibly be larger.

We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the EPA National Emission Standard for Hazardous Air Pollutants (“NESHAP”) for industrial, commercial, and institutional boilers and process heaters (also known as “Boiler MACT”), which was issued but subsequently vacated in 2007. The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers. The EPA issued a new Boiler MACT rule on March 21, 2011, but on May 18, 2011 it published a notice delaying the effective date of the new rule to allow the agency to reconsider its effect.  On December 2, 2011, the EPA released proposed amendments to the new Boiler MACT rule, and the public comment period closed on February 21, 2012.  The proposed rule is more stringent than the vacated version depending on boiler sizes, whether the source is new or existing, and it sets work practice standards for various emissions.  Significantly, on January 9, 2012, the District Court for the District of Columbia vacated the May 2011 action by the EPA, which delayed the implementation of the new Boiler MACT.  The effect of the vacatur is that the revisions to the Boiler MACT became immediately effective.  Notwithstanding the vacatur, the EPA issued a “No Action Assurance Letter” to establish that it will exercise its enforcement discretion to not pursue enforcement action for violations of certain notification deadlines in the final Major Source Boiler MACT rule. The EPA intends to issue the final reconsideration rule prior to any of the compliance dates for existing sources.  In the absence of a final NESHAP for industrial, commercial, and institutional boilers and process heaters, we are waiting for state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed. We currently cannot estimate the amount that will be needed to comply with federal or possible state technology requirement regarding air emissions from our boilers.

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill that, among other things, would have established a cap-and-trade system to regulate greenhouse gas (“GHG”) emissions and would have required an 80% reduction in GHG emissions from sources within the United States between 2012 and 2050. In 2009, the U.S. Senate also considered a number of comparable measures. One such measure, the Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, was reported out of the Senate Committee on Energy and Natural Resources, but not considered by the full Senate. Although these bills were not enacted by the 111th Congress, the United States Congress is likely to again consider a climate change bill in the future.  Moreover, almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  Most of these “cap and trade” programs work by requiring major sources of emissions to acquire and surrender GHG emission ‘‘allowances’’ corresponding to their annual emissions of GHGs.  The number of GHG emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Any laws or regulations that may be adopted to restrict or reduce emissions of U.S. GHGs could require us to incur increased operating costs, and could have an adverse effect on the revenues we generate from carbon

12

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

On April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011, although it does not require immediate reductions in GHG emissions. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although it remains the subject of several pending lawsuits filed by industry groups.  The tailoring rule establishes new GHG emissions thresholds that determine those stationary sources that must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the CAA. The permitting requirements of the PSD program apply to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the tailoring rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the tailoring rule, which became effective on July 1, 2011, requires preconstruction permits including BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year.  Phase III of the tailoring rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process.  Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., beginning in 2011 for emissions occurring in 2010.  Restrictions on emissions of carbon dioxide could adversely affect our cost of doing business and demand for the ethanol we produce.

On February 3, 2010, the EPA announced final revisions to the RFS Program, known as RFS2. This rule makes changes to the RFS program as required by the EISA. The revised statutory requirements establish new specific annual volume standards for cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel that must be used in transportation fuel. The revised statutory requirements also include new definitions and criteria for both renewable fuels and the feedstock used to produce them, including new greenhouse gas emission thresholds as determined by lifecycle analysis. The regulatory requirements for RFS2 will apply to domestic and foreign producers and importers of renewable fuel used in the U.S.

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

13

The EPA recently finalized the 2012 annual RFS percentages.  The2012 RFS volume standard is 15.2 billion gallons, of which 13.2 billion gallons are related to corn based ethanol.

In order to qualify for these new volume categories, fuels must demonstrate that they meet certain minimum greenhouse gas reduction standards, based on a lifecycle assessment, in comparison to the petroleum fuels they displace. Generally, ethanol plants either must meet the 20% reduction test or are grandfathered under special provisions.

Where You Can Find Additional Information

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

Our public internet site is http://www.aventinerei.com. We will make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and Forms 3, 4, and 5 filed on behalf of directors and executive officers, to the extent we and such persons are required to file such statements and reports, and any amendments to those reports filed or furnished pursuant to the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Also available on our website, and available in print upon request, are our corporate governance guidelines, the charters of our audit and compensation 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.

14

Item 1A.  Risk Factors

Risks Related to Our Business

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

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

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

Our principal sources of liquidity are cash and cash equivalents on hand, cash provided by operations, and cash provided by our revolving credit facility with Wells Fargo Capital Finance, LLC.  On July 20, 2011, Aventine and each of its subsidiaries, as co-borrowers (collectively, the “Borrowers”), entered into a revolving credit facility (the “New Revolving Facility”) with the lenders party thereto (the “Lenders”) and Wells Fargo Capital Finance LLC, as Lender and as agent for the Lenders (in such capacity “Wells Fargo”) (as amended, and as may be amended, supplemented or otherwise modified from time to time, the “New Revolving Facility Agreement”), with a $50.0 million commitment.  The New Revolving Facility has a borrowing base that is principally supported by accounts receivable and inventory.   As of February 28, 2012, the Company had letters of credit outstanding of $9.2 million between the Company and its subsidiaries, as holders, and Wells Fargo, as issuer.

Our liquidity position is significantly influenced by our operating results, which in turn are substantially dependent on commodity prices, especially prices for corn, ethanol, natural gas, and unleaded gasoline. As a result, adverse commodity price movements adversely impact our liquidity. We cannot assure you that the amounts of cash available from operations, together with the New Revolving Facility, will be sufficient to fund our operations.

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

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

As of December 31, 2011, we had an aggregate of approximately $216.3 million in debt outstanding due primarily to a $225 million term loan facility (as amended, and as may be amended, supplemented or otherwise modified from time to time, the “Term Loan Facility”) with Citibank N.A., as administrative and collateral agent (the “Term Loan Agreement”).  In addition, we had availability under the New Revolving Facility of approximately $20.1 million as of December 31, 2011. As a result of our indebtedness, we will use a portion of our cash flow to pay interest and principal when due, which will reduce the cash available to

15

finance our operations and other business activities and could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

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

·incur additional indebtedness and issue stock;

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

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

·make investments;

·enter into transactions with affiliates;

·create or incur liens to secure debt;

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

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

·incur dividend or other payment restrictions affecting subsidiaries;

·make capital expenditures beyond specified limits;

·engage in specified business activities; and

·acquire facilities or other businesses.

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

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

We may be unable to secure additional financing.

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

·general economic and capital market conditions;

·conditions in biofuels markets;

·regulatory developments;

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

·investor confidence in the biofuels industry and in us;

·the continued reliable operation of our ethanol production facilities; and

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

16

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

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

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt, selling assets, reducing or delaying capital investments or raising additional capital.

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

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

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

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

The principal raw material we use to produce ethanol and ethanol by-products is corn. In 2011, we purchased approximately 93.2 million bushels of corn, which comprised about 74.9% of our total cost of production. We believe a systemic shift has occurred in the marketplace for corn, and the price of corn will remain significantly higher than the historical averages.

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

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

17

increased prices for corn. We expect the price of corn to continue to remain at levels that would be considered as high when compared to historical periods.

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

We rely upon third parties for our supply of natural gas which is consumed in the production of ethanol, including at our natural gas-fired corn dry mill plant in Pekin, Illinois and our natural gas-fired corn dry mill plants in Mt. Vernon, Indiana and Aurora, Nebraska.  The prices for and availability of natural gas are subject to volatile market conditions. These market conditions often are affected by factors beyond our control such as weather conditions, overall economic conditions and foreign and domestic governmental regulation and relations. Significant disruptions in the supply of natural gas could temporarily impair our ability to produce ethanol for our customers. Further, increases in natural gas prices or changes in our natural gas costs relative to natural gas costs paid by competitors may adversely affect our results of operations and financial condition. The price fluctuation in natural gas prices over the ten year period from 2002 through December 31, 2011, based on the New York Mercantile Exchange, (“NYMEX”), daily futures data, has ranged from a low of $2.32 per MMBtu in January 2002 to a high of $13.42 per MMBtu in October 2005. We currently use approximately 5.6 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 start-up of our Aurora West and Canton facilities.

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

At any given time, contract prices for ethanol may be at a price level different from the current prevailing price, and such a difference could materially adversely affect our results of operations and financial condition.  At December 31, 2011, we had fixed-priced contracts to sell 3.9 million gallons of ethanol.

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

In an attempt to minimize the effects of the volatility of the price of corn, natural gas, electricity and ethanol (‘‘commodities’’), we may take economic hedging positions in the commodities. Economic hedging arrangements also expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or there is a change in the expected differential between the underlying price in the hedging agreement and the actual price of the commodities. Although we attempt to link our economic hedging activities to sales plans and pricing activities, occasionally such hedging activities can themselves result in losses. As a result, our results of operations may be adversely affected during periods in which corn and/or natural gas prices increase.

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

On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which, among other things, aims to improve transparency and accountability in derivative markets. While the Dodd-Frank Act increases the regulatory authority of the Commodities Futures Trading Commission (the “CFTC”) regarding over-the-counter derivatives, there is uncertainty on several issues related to market clearing, definitions of market participants, reporting, and capital requirements, and many details remain to be addressed in CFTC rulemaking proceedings.  In the third quarter of 2011 the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until no later than July 16, 2012. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations establishing speculative position limits relating to certain U.S. exchange-listed physical commodity futures contracts, as well as to swaps that reference the specified contracts and contracts settling against the specified contracts that are executed on, or pursuant to, rules of a

18

foreign board of trade providing direct access to U.S persons. Certain bona fide hedging transactions or derivative instruments would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective.  At this time we are unable to predict what effect, if any, these provisions of the Dodd-Frank Act will have on our results of operations or financial condition.

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

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

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

We sell co-products and bio-products that are remnants of the ethanol production process in order to offset our corn costs and increase profitability. Historically, sales prices for these co-products have tracked along with the price of corn. However, there have been occasions when the value of these co-products and bio-products has lagged behind increases in corn prices. As a result, we may occasionally generate less revenue from the sale of these co-products and bio-products relative to the price of corn. In addition, several of our co-products compete with similar products made from other plant feedstock. The cost of these other feedstocks may not rise as corn prices increase. Consequently, the price we may receive for these products may not rise as corn prices rise, thereby lowering our cost recovery percentage relative to corn.

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

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

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

According to the RFA, domestic ethanol capacity, including capacity under construction, has increased significantly from approximately 1.8 billion gallons per year at January 1999 to 14.9 billion gallons per year at January 2012. Demand for ethanol in 2011 decreased 3.1% from 2010, and increased 22% over 2009, 37% over 2008, and 93% over 2007 through increased penetration into new markets and a government mandate; however the production capacity of U.S. ethanol producers continues to exceed demand. For the first ten months of 2011, the production capacity of U.S. ethanol producers exceeded the demand by approximately 7.5%.  If additional demand for ethanol is not created, either through discretionary blending, exports, or an increase in the blending percentage allowed by the EPA, the excess supply may cause additional plants to shutter production or cause ethanol prices to decrease further, perhaps substantially.

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

19

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.

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

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

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

We sell ethanol to most of the major integrated oil companies and a significant number of large, independent refiners and petroleum wholesalers. Our trade receivables result primarily from our ethanol marketing operations. As a general policy, collateral is not required for receivables, but customers’ financial condition and creditworthiness are evaluated regularly. Credit risk concentration related to our accounts receivable results from our top ten customers having generated 65.7%, 61.7% and 54.7% of our consolidated net sales for the years ended December 31, 2011, 2010 and 2009, respectively. In 2011, 2010 and 2009, two customers represented more than 10% of Aventine’s consolidated net sales.  If we would suddenly lose a major customer and not be able to replace the demand for our product very quickly, it could have a material impact on our sales and profitability.

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

As of December 31, 2011, the substantial majority of our income was derived from the sale of ethanol and the related by-products that we produced at our facilities. Our operations may be subject to significant interruption if any of our facilities experiences a major accident or is damaged by severe weather or other natural disaster. In addition, our operations may be subject to labor disruptions and unscheduled downtime, or other hazards inherent in our industry. Some of those hazards may cause personal injury and loss of life, severe damage to or destruction of property, natural resources and equipment, pollution and environmental damage, clean-up responsibilities, and repairs to resume operations and may result in suspension or termination of operations and the imposition of civil or criminal penalties. As protection against these hazards, we maintain property, business interruption and casualty insurance which we believe is in accordance with customary industry practices, but we cannot provide any assurance that this insurance

20

will be adequate to fully cover the potential hazards described above or that we will be able to renew this insurance on commercially reasonable terms or at all.

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

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

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

·inclement weather and natural disasters;

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

·raw material supply disruptions;

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

·transportation disruptions.

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

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

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

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

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

Any delay or failure in making the changes in or expansion of infrastructure could hurt the demand or prices for our products, impede our delivery of products, impose additional costs on us or otherwise have a material adverse effect on our business, results of operations or financial condition. Our business is dependent on the continuing availability of infrastructure and any infrastructure disruptions could have a material adverse effect on our business, results of operations, and financial condition.

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

On or about March 23, 2010, in accordance with the terms of a stipulation filed with the Bankruptcy Court, we paid approximately $2.1 million to the Aurora Co-operative, representing penalties of (i) approximately $0.8 million, arising under a Master Development Agreement with the Aurora Co-operative

21

for failure to complete construction of the Aurora West facility, for the period of July 1, 2009 through and including December 31, 2009, and (ii) approximately $1.3 million in the event that we had not completed the Aurora West facility by September 30, 2010  for each month starting from January 1, 2010 through and including September 30, 2010.  Beginning on October 1, 2010, we have been subjected to additional penalties of $138,889 per month, and will remain subject to these penalties until the plant (although constructed) is operational or total penalties equaling $5.0 million have been paid by us, whichever comes first.  The Aurora West facility was substantially completed by the end of the fourth quarter of 2010; we have delayed start up to date of the plant, but expect the Aurora West facility to become operational in 2012, subject to weather conditions, commodity prices and the availability of working capital.

The Aurora Co-operative has informed our company that it believes it has the right pursuant to an agreement between our company and the Aurora Co-operative, dated March 23, 2010, to acquire the land on which the Aurora Facility is located for a purchase price of $16,500 per acre.  It is the Aurora Co-operative’s belief that this option arises on July 31, 2012, provided in its opinion that that the Aurora Facility is not operational at certain production levels for thirty consecutive business days.  We do not agree with the positions asserted by the Aurora Co-operative with respect to the scope and/or availability of this real estate purchase option.  Our company intends to diligently to pursue completion of the plant as provided under the March 26, 2010 agreement and vigorously defend against any assertion that the Aurora Co-operative has any right to repurchase the land or any improvements on the land.  However, there is no certainty that this disagreement will not result in litigation or that a decision adverse to our interest will not be rendered by a court with respect to this matter that could have a material adverse effect on our business, results of operations and financial condition.

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

In the U.S., we compete with other corn processors and refiners, including Archer Daniels Midland Company, Green Plains Renewable Energy Inc., Valero Energy Corporation, Biofuels Energy Corporation, Hawkeye Holdings, Inc., Pacific Ethanol Inc., Cargill, Incorporated and A.E. Staley Manufacturing Company, a subsidiary of Tate & Lyle plc. Some of our competitors are divisions of larger enterprises and have greater financial resources than we do. Certain of our competitors have significantly larger market shares than we have, and tend to be price leaders in the industry.  If any of these competitors were to significantly reduce their prices, our business, operating results and financial condition could be adversely affected.  Although many of our competitors are larger than we are, we also have smaller competitors. Farm cooperatives comprised of groups of individual farmers have been able to compete successfully. As of December 2011, the top ten domestic producers accounted for approximately 49.0% of all production. If our competitors consolidate or otherwise grow and/or we are unable to similarly increase our size and scope, our business and prospects may be significantly and adversely affected.

Our competitors also include plants owned by farmers who earn their livelihood through the sale of corn, and hence may not be as focused on obtaining optimal value for their produced ethanol as we are and would potentially be more willing to sell their ethanol at a lower price than us.

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

Imported ethanol was generally subject to a $0.54 per gallon tariff and a 2.5% ad valorem tax that was designed to offset the $0.45 per gallon ethanol subsidy formerly available under the federal excise tax incentive program for refineries and blenders that mix ethanol with their gasoline. These tariffs and subsidies expired on December 31, 2011.  With the expiration of the tariff, other countries, such as Brazil, may be more competitive in the U.S. ethanol market.

22

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

Various federal and state laws, regulations and programs have led to increased use of ethanol in fuel. For example, certain laws, regulations and programs provide economic incentives to ethanol producers and users. Among these regulations are (1) the RFS, which requires an increasing amount of renewable fuels to be used in the U.S. each year, (2) the VEETC, which provided a tax credit of $0.45 per gallon on 10% ethanol blends that expired in 2011, (3) the small ethanol producer tax credit, for which we do not qualify because of the size of our ethanol plants, and (4) the federal “farm bill,” which establishes federal subsidies for agricultural commodities including corn, our primary feedstock. These laws, regulations, and programs are regularly changing, and sections of the RFS currently are the subject of legal challenges in federal court. Federal and state legislators and environmental regulators could adopt or modify laws, regulations, or programs that could affect adversely the use of ethanol. For example, California’s Low Carbon Fuel Standard Program makes it difficult for corn-based ethanol produced in many Midwestern states to be used as a fuel in California.  A federal district court recently held that the program is unlawful and issued an order suspending it.  California has appealed the decision, however, and the courts could reverse the decision and lift the stay.  In addition, some state legislators oppose the mandatory use of ethanol because their states must transport it from other corn-producing states, which could significantly increase gasoline prices in the state.  Legislation is now pending before certain state legislatures, which, if enacted, would repeal the state’s renewable fuel requirement and potentially decrease demand for ethanol in the state.

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

The EPA’s RFS2 includes requirements that the lifecycle greenhouse gas emissions of a qualifying renewable fuel must be less than the lifecycle greenhouse gas emissions of the 2005 baseline average gasoline or diesel fuel that it replaces. The lifecycle greenhouse gas emissions threshold for renewable fuel (e.g., ethanol) is 20%. Fuels from existing capacity of current facilities and from facilities that commenced construction prior to December 19, 2007, are exempt or grandfathered from the 20% lifecycle requirement under certain circumstances. The EPA issued a Direct Final Rule that, among other things, requires all plants that commenced construction prior to the enactment of the EISA to complete construction by December 19, 2010. Plants not exempt or grandfathered must include advanced efficient technologies as defined by the regulations in order to meet the RFS2 requirements. As a result, the Canton facility or other facilities we may construct or acquire may not be exempt from the 20% lifecycle requirement and could require inclusion of advanced efficient technologies, which could require substantial capital.

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

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

23

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

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

We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we presently own or operate (or properties we formerly owned or operated) and at off-site locations where we arranged for the disposal of hazardous wastes. For instance, over ten years ago, soil and groundwater contamination from fuel oil contamination at a storage site was identified at our Illinois facility. The fuel oil tanks were removed and a portion of the area has been capped, but no remediation has been performed. If any of these sites are subject to investigation and/or remediation requirements, we may incur strict and/or joint and several liability under the Comprehensive Environmental Response, Compensation and Liability Act (or analogous state laws) or other environmental laws which impose strict liability for all or part of the costs of such investigation, remediation, or removal costs and for damages to natural resources whether the contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with applicable laws at the time those actions were taken. We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties or other impacts of our operations. While costs to address contamination or related third-party claims could be significant, based upon currently available information, we are not aware of any material liability relating to contamination or such third party claims.  We have not accrued any amounts for environmental matters as of December 31, 2011. The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

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

Our air emissions are subject to the federal Clean Air Act, as amended, and similar state laws which generally require us to obtain and maintain air emission permits for our ongoing operations, as well as pre-approval for any expansion or construction of existing facilities or new facilities or modification of

24

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

Federal and state environmental authorities have been investigating alleged excess VOCS emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities. The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility. If authorities require us to install controls, we would anticipate that costs would be approximately $6.5 million, which would be considerably higher than the approximately $3.4 million we incurred in connection with a similar investigation at our Nebraska facility due to the larger size of the Illinois wet mill facility. As of now, we have not established reserves for possible costs we may incur in connection with this investigation. In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material. With respect to the investigation of our Nebraska facility, we were required to pay a fine of $40,000. Due to the larger capacity of the Illinois facilities, the fine could possibly be larger.

We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the EPA National Emission Standard for Hazardous Air Pollutants (“NESHAP”) for industrial, commercial, and institutional boilers and process heaters (also known as “Boiler MACT”), which was issued but subsequently vacated in 2007. The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers. The EPA issued a new Boiler MACT rule on March 21, 2011, but on May 18, 2011 it published a notice delaying the effective date of the new rule to allow the agency to reconsider its effect.  On December 2, 2011, the EPA released proposed amendments to the new Boiler MACT rule, and the public comment period closed on February 21, 2012.  The proposed rule is more stringent than the vacated version depending on boiler sizes, whether the source is new or existing, and it sets work practice standards for various emissions.  Significantly, on January 9, 2012, the District Court for the District of Columbia vacated the May 2011 action by the EPA, which delayed the implementation of the new Boiler MACT.  The effect of the vacatur is that the revisions to the Boiler MACT became immediately effective.  Notwithstanding the vacatur, the EPA issued a “No Action Assurance Letter” to establish that it will exercise its enforcement discretion to not pursue enforcement action for violations of certain notification deadlines in the final Major Source Boiler MACT rule. The EPA intends to issue the final reconsideration rule prior to any of the compliance dates for existing sources.  In the absence of a final NESHAP for industrial, commercial, and institutional boilers and process heaters, we are waiting for state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed. We currently cannot estimate the amount that will be needed to comply with federal or possible state technology requirements regarding air emissions from our boilers.

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill that, among other things, would have established a

25

cap-and-trade system to regulate greenhouse gas (“GHG”) emissions and would have required an 80% reduction in GHG emissions from sources within the United States between 2012 and 2050. In 2009, the U.S. Senate also considered a number of comparable measures. One such measure, the Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, was reported out of the Senate Committee on Energy and Natural Resources, but not considered by the full Senate. Although these bills were not enacted by the 111th Congress, the United States Congress is likely to again consider a climate change bill in the future.  Moreover, almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.   Most of these “cap and trade” programs work by requiring major sources of emissions to acquire and surrender GHG emission ‘‘allowances’’ corresponding to their annual emissions of GHGs.  The number of GHG emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Any laws or regulations that may be adopted to restrict or reduce emissions of U.S. GHGs could require us to incur increased operating costs, and could have an adverse effect on the revenues we generate from carbon dioxide sales.

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

On April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011, although it does not require immediate reductions in GHG emissions. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although it remains the subject of several pending lawsuits filed by industry groups.  The tailoring rule establishes new GHG emissions thresholds that determine those stationary sources that must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the CAA. The permitting requirements of the PSD program apply to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities.  Phase I of the tailoring rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the tailoring rule, which became effective on July 1, 2011, requires preconstruction permits including BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year.  Phase III of the tailoring rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process.  Additionally, in September 2009, the EPA issued a final rule requiring the

26

reporting of GHG emissions from specified large GHG emission sources in the U.S., beginning in 2011 for emissions occurring in 2010.  Restrictions on emissions of carbon dioxide could adversely affect our cost of doing business and demand for the ethanol we produce.

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

We depend on rail, truck, and barge transportation to deliver corn to us and to distribute ethanol to our customers. Ethanol is not currently distributed by pipeline. Disruption to the timely supply of these transportation services or increases in the cost of these services for any reason, including the availability or cost of fuel or railcars to serve our facilities, 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 customers, and could have a material adverse effect on our financial performance.

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, 2011, approximately 45% of our employees were unionized. Our unionized employees are hourly workers located at our Illinois facilities. The unionized employees are covered by a collective bargaining agreement between our subsidiary, Aventine Renewable Energy, Inc., and the Union.

On October 29, 2010, the Union ratified a new collective bargaining agreement with Aventine Renewable Energy, Inc. for our hourly production workers in Pekin, Illinois. This new agreement is effective November 1, 2010, and runs through October 31, 2012. The agreement contains provisions, terms and conditions that are customary in collective bargaining agreements of this type, including, among other things, wages, hours, work assignments, management rights, seniority, arbitration and grievance procedures, benefits, vacations, and holidays. The benefit and base wage packages for the currently covered employees remain substantially similar to those in the previous collective bargaining agreement; the currently covered employees also received lump sum annual payments of $750 in November 2010 and November 2011. Employees hired after November 1, 2010, will only be eligible for the 401(k) program as their retirement benefit. The collective bargaining agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse affect on our business, financial condition, and results of operations. There is no certainty that the current collective bargaining agreement will be extended or that a new collective bargaining agreement will be reached.

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

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

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

We rely on network infrastructure and enterprise applications, and internal technology systems for our operational, marketing support and sales, and product development activities. The hardware and

27

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

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

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

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

Risks Related to Our Common Stock

The trading price for the shares of our common stock may be volatile. The liquidity of any market for the shares of our common stock will depend on a number of factors, including:

·the number of stockholders;

·our operating performance and financial condition;

·the market for similar securities; and

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

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

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

·actual or expected fluctuations in our operating results;

·actual or expected changes in our growth rates or our competitors’ growth rates;

·conditions in our industry generally;

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

28

·our inability to raise additional capital;

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

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

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

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

Ownership of our capital stock is concentrated among our largest stockholders and their affiliates.

Our three largest stockholders collectively own approximately 64% of our outstanding common stock. Consequently, these stockholders have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

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

The market price of the shares of our common stock could decline as a result of sales by our existing stockholders or the perception that such sales might occur. These sales also might make it difficult for our equity securities to be sold in the future at a time and price that we deem appropriate. If any of our existing stockholders sell a significant number of shares, the market price of our common stock could be adversely affected.

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

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

We have “blank check” preferred stock.

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

29

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

We are authorized to issue 15,000,000 shares of common stock, $0.001 par value per share. As of February 10, 2012, there were 8,392,341 shares of common stock issued and outstanding. Since the holders of our common stock do not have cumulative voting rights, the holders of a majority of the shares of common stock present, in person or by proxy, will be able to elect all of the members of our Board of Directors. The holders of shares of our common stock do not have preemptive rights or rights to convert their common stock into other securities.

Our common stock has been thinly traded and there has been no active trading market for our common stock and an active trading market may not develop.

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

Item 1B.  Unresolved Staff Comments

None.

Item 2.  Properties

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

30

Facilities

The table below provides an overview of our ethanol plants as of December 31, 2011.

	Illinois Wet Mill Facility	Illinois Dry Mill Facility	Nebraska Facility	Mt. Vernon Facility	Aurora West Facility	Canton Facility
Location	Pekin, IL	Pekin, IL	Aurora, NE	Mt. Vernon, IN	Aurora, NE	Canton, IL
Ownership	100%	100%	100%	100%	100%	100%
Land (acres)	83	11	30	86	84	289
Year constructed	1981(1)	2007	1995	2010(2)	2010	2006
Process	Wet Milling	Dry Milling	Dry Milling	Dry Milling	Dry Milling	Dry Milling
Annual ethanol capacity as of December 31, 2011 (in millions of gallons)	100	57	45	110	(3)	(4)
Electricity co-generation capability	Yes	No	No	No	No	No
Power source	Coal, Natural Gas	Natural Gas	Natural Gas	Natural Gas	Natural Gas	Coal, Natural Gas
Distribution method	Rail, Truck, Barge	Rail, Truck, Barge	Rail, Truck	Rail, Truck, Barge	Rail, Truck	Rail, Truck, Barge

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

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

(3)The Aurora West facility was substantially completed as of December 31, 2010; however, the Company has not begun start-up operations.  Annual capacity is 110 million gallons.

(4)The Canton facility was purchased on August 6, 2010; however, the Company has not begun start-up operations.  Annual capacity is 38 million gallons.

Land for Future Expansion

Location	Owned/ Leased	Property Size (acres)	Description
Pekin, IL	Owned	26	The Company holds this property for future development.
Canton, IL	Owned	289	Purchased during 2010.

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

31

Item 3.  Legal Proceedings

On November 6, 2008, the Company commenced an action against JP Morgan Securities, Inc. and JP Morgan Chase Bank, N.A. (hereinafter collectively referred to as ‘‘JP Morgan’’) in the Tenth Judicial Circuit in Tazewell County, Illinois. The Company’s complaint relates to losses incurred of approximately $31.6 million as a result of investments in Student Loan Auction Rate Securities purchased through JP Morgan.   This state court litigation is currently under a stay by the Circuit Court, which has prevented further prosecution of this dispute in that forum.  On June 10, 2011 the Company filed a request for arbitration with FINRA.  The request has been granted and the matter will move forward under FINRA Code of Arbitration Proceedings.    At this time, the Company is unable to determine the impact such litigation will have on our business, operating results, financial condition and cash flows.

On April 7, 2009, the Debtors filed voluntary petitions with the Bankruptcy Court to reorganize under Chapter 11 of the Bankruptcy Code.  The Plan was confirmed by order entered by the Bankruptcy Court on February 24, 2010, and became effective on March 15, 2010, the date on which the Company emerged from protection under Chapter 11 of the Bankruptcy Code.  Since March 15, 2010, certain of the Debtors’ cases have been closed by order of the Bankruptcy Court, effective December 20, 2010; however, the cases of Aventine Renewable Energy, Inc. and Nebraska Energy, L.L.C. remain open, wherein certain creditor claims remain subject to dispute and further adjudication, as do certain claims and potential claims by the Debtors against various third parties.  At this time, the Company is unable to determine the impact such litigation will have on its business, operating results, financial condition and cash flows.

On April 19, 2011, the Company was notified of the EPA’s intent to file an administrative complaint against Aventine Renewable Energy, Inc. for a release which occurred in March 2008.  The EPA noted that they would be seeking a penalty of approximately $0.2 million.  The Company has responded stating that its position is that such claims are barred by the bankruptcy proceedings.  At this time, the Company is unable to determine the impact such litigation will have on its business, operating results, financial condition and cash flows.

The Company initiated a civil action against E-Biofuels, LLC (“E-Biofuels”) in 2009 related to breach of agreement, and asked for not less than $3.0 million in compensation.  This suit was later transferred to the Bankruptcy Court and subsequently settled in the Company’s favor on July 6, 2011.  Under the terms of the settlement, the Company received $0.2 million in cash and 425,000 shares of Imperial (E-Biofuels’ parent company) stock.   The stock was valued at $0.7 million on the date of receipt of July 6, 2011.  The Company also had previously recorded a liability related to tax credits of $0.7 million which was relieved by the settlement.  The net gain of $1.6 million is included in other non-operating income for the year ended December 31, 2011, on the statement of operations.  The stock was booked as short-term investments which are classified as available for sale securities on the balance sheet.  For the year ended December 31, 2011, the Company booked a loss on available for sale securities of $0.5 million related to the decrease in the current trading price of the stock which is included in other non-operating income on the income statement.

On September 3, 2009, Union Tank Car Company (“Union Tank”) filed notice of a claim against the Company with the Bankruptcy Court for a general unsecured claim in the amount of $82.6 million for certain estimated end charges including railcar cleaning costs and unpaid rental payments for leased railcars.  Union Tank also filed an administrative claim against the Company in the amount of $0.1 million for the alleged use of railcars after the effective date of the rejection of the leases for such railcars.  The Company disputed both of these claims.  On September 30, 2011, the Court ruled that the claim shall be allowed in the amount of $27.6 million.  Partial distribution of shares on account was made October 31, 2011, in accordance with the terms of the Plan and at such time as the distribution was made to other holders of claims in classes five and six that were allowed as of September 30, 2011.  As a result of the settlement on September 30, 2011, the Company reversed the related reserve for this matter of $0.1 million through other non-operating income on the statements of operations.

32

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

Item 4.  Mine Safety Disclosures

Not applicable.

33

PART II

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

Market for our Common Stock and Holders of Record

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

As of February 24, 2012, the last reported sales price of our common stock on the OTCBB was $3.55 per share of common stock. As of February 10, 2012, there were 8,392,341 shares of our common stock outstanding, net of 74,841 shares held in treasury, held by approximately 87 holders of record, based upon the records of our transfer agent, and approximately 184 additional holders of record that hold through the facilities of The Depository Trust Company. These numbers do not include stockholders for whom shares are held in a nominee or “street” name. The following table sets forth the range of high and low bid quotation prices per share of our common stock as reported by the applicable exchange or quotation system. The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions.

	2011				2010
Period	High		Low		High		Low
January 1, 2010 — February 28, 2010 (Predecessor)	—		—		$	0.37	$	0.16
March 1, 2010 — March 31, 2010 (Successor)	—		—		$	47.25	$	43.75
First Quarter	$	29.50	$	25.75	—		—
Second Quarter	$	26.35	$	12.00	$	43.75	$	30.00
Third Quarter	$	12.50	$	10.00	$	32.20	$	20.00
Fourth Quarter	$	10.50	$	5.90	$	27.50	$	23.65

Dividends

We currently intend to retain earnings, if any, to finance the growth and development of our business and we do not expect to pay any cash dividends on our common stock in the foreseeable future.  Payment of future dividends, if any, will be at the discretion of our Board of Directors and will depend on many factors, including general economic and business conditions, our strategic plans, our financial results and condition, legal requirements and other factors as our Board of Directors deems relevant.  In addition, pursuant to provisions of the Term Loan Agreement and the New Revolving Facility, the Company has limitations on the amount of dividends and distributions it can declare and pay, and we may in the future become subject to debt instruments or other agreements that further limit our ability to pay dividends.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing — Term Loan Agreement” and “— New Revolving Facility.”  We did not declare or pay cash dividends on our common stock during the years ended December 31, 2011 or 2010.

Recent Sales of Unregistered Securities

The following relates to certain issuances of equity securities that have occurred during the period covered by this Annual Report on Form 10-K, and have not been registered under the Securities Act of 1933,

34

as amended (the “Securites Act”):

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

On May 13, 2011, pursuant to our Plan and Confirmation Order, the Company commenced a pro-rata distribution, consisting of 19,414 shares of common stock, to holders of the Company’s pre-petition notes and to holders of allowed general unsecured claims, with 9,806 shares distributed to holders of pre-petition notes and 9,608 shares to holders of allowed general unsecured claims.  We received no proceeds from the issuance.  Consistent with our Confirmation Order and applicable law, we relied on Section 1145 (a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the issuance of the shares.

On October 31, 2011, the Company commenced a pro-rata distribution, consisting of 774,425 shares of common stock, to holders of the Company’s pre-petition notes and to holders of allowed general unsecured claims, with 399,993 shares distributed to holders of pre-petition notes and 374,432 shares to holders of allowed general unsecured claims.  Approximately 0.4 million shares of common stock are reserved for future distributions to these holders.  These shares will be distributed as remaining claims are settled in accordance with the Plan.

35

Item 6.  Selected Financial Data

The following selected consolidated financial data as of and for the twelve months ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010 and each of the three years ended December 31, 2009, 2008 and 2007, has been derived from the audited consolidated financial statements of the Company. The following data should be read in conjunction with the consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this Form 10-K.

On March 15, 2010, we emerged from bankruptcy and implemented fresh-start accounting in accordance with ASC 852 using a Convenience Date of February 28, 2010. Therefore, the consolidated financial statements prior to March 1, 2010, reflect results based upon the historical cost basis of the Company while the post-emergence consolidated financial statements reflect the new basis of accounting incorporating the fair value adjustments made in recording the effects of fresh-start reporting. Therefore, the post-emergence periods are not comparable to the pre-emergence periods. As a result of the application of fresh start accounting, our consolidated financial statements prior to and including February 28, 2010, represent the operations of our pre-reorganization predecessor company and are presented separately from the consolidated financial statements of our post-organization successor company.

We have included EBITDA and Adjusted EBITDA primarily as performance measures because management uses them as key measures of our performance. EBITDA is defined as earnings (which include gains or losses on derivative transactions) before interest expense, interest income, income tax expense, depreciation and amortization. EBITDA is not a measure of financial performance under accounting principles generally accepted in the U.S. (“GAAP”) and should not be considered an alternative to net earnings or any other measure of performance under GAAP. 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 GAAP. For example, EBITDA includes non-recurring loss items which are reflected in the statement of operations.

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

Management believes EBITDA and Adjusted EBITDA are meaningful supplemental measures of operating performance and so highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures.  We also believe that securities analysts, investors, and other interested parties frequently use EBITDA in the evaluation of companies, many of which present EBITDA when reporting their results.  Additionally, management provides an Adjusted EBITDA measure so that investors will have the same financial information that management uses with the belief that it will assist investors in properly assessing the Company’s performance on a year-over-year and

36

quarter-over-quarter basis.  Our management and external users of our financial statements, such as investors, commercial banks, research analysts, and others, use EBITDA and Adjusted EBITDA to assess:

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

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

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

	Successor						Predecessor
	For the Year Ended  December 31,			For the Ten Months Ended  December 31,			For the Two Months Ended  February 28,			For the Year Ended December 31,
	2011			2010			2010			2009			2008			2007
	(In thousands, except for per share amounts)
Statement of Operations Data:
Net sales	$	887,587		$	370,559		$	77,675		$	594,623		$	2,248,301		$	1,571,607
Cost of goods sold	857,377			349,751			66,686			585,904			2,239,340			1,497,807
Gross profit	30,210			20,808			10,989			8,719			8,961			73,800
Selling, general and administrative expenses	32,714			34,068			4,608			26,694			35,410			36,367
Start-up activities	—			1,177			—			—			—			—
Demobilization costs associated with expansion projects	—			—			—			—			9,874			—
Impairment of plant development costs	—			—			—			—			1,557			—
Other expense (income)	3,329			1,681			515			1,510			(2,936		)	(1,113		)
Operating income (loss)	(5,833		)	(16,118		)	5,866			(19,485		)	(34,944		)	38,546
Net income (loss)	(43,390		)	(25,464		)	(266,293		)	(46,260		)	(48,326		)	35,137
Net income (loss) attributable to non-controlling interest	—			—			—			—			(1,230		)	1,338
Net income (loss) attributable to controlling interest	$	(43,390	)	$	(25,464	)	$	(266,293	)	$	(46,260	)	$	(47,096	)	$	33,799
Per Share Data:
Income (loss) per common share-basic	$	(4.80	)	$	(2.97	)	$	(6.14	)	$	(1.08	)	$	(1.12	)	$	0.81
Basic weighted-average common shares	9,047			8,584			43,401			42,968			42,136			41,886
Income (loss) per common share-diluted	$	(4.80	)	$	(2.97	)	$	(6.14	)	$	(1.08	)	$	(1.12	)	$	0.80
Diluted weighted-average common and common equivalent shares	9,047			8,584			43,401			(42,968		)	42,136			42,351
Balance Sheet Data:
Total assets	$	414,238		$	593,978		$	364,305		$	712,696		$	799,459		$	762,185
Total debt(1)	$	216,334		$	347,958		$	110,252		$	42,765		$	352,200		$	300,000
Stockholders’ equity	$	158,681		$	201,658		$	219,923		$	267,532		$	308,796		$	343,871
Other Data (unaudited):
EBITDA	$	6,054		$	(7,566	)	$	(262,702	)	$	(26,164	)	$	(38,009	)	$	49,708
Adjusted EBITDA	$	21,428		$	1,335		$	8,938		$	8,812		$	878		$	56,913
Gallons sold	257,460			152,517			31,478			277,471			935,986			690,171
Capital expenditures	$	23,330		$	77,672		$	2,086		$	2,279		$	265,878		$	235,211
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	(8,487	)	$	(19,205	)	$	(11,687	)	$	40,816		$	35,601		$	47,581
Investing activities	$	(23,330	)	$	(94,552	)	$	(2,086	)	$	(279	)	$	(83,133	)	$	(347,781	)
Financing activities	$	33,389		$	63,051		$	46,427		$	(11,291	)	$	53,700		$	287,580

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

37

	Successor						Predecessor
	For the Year Ended  December 31,			For the Ten Months Ended December 31,			For the Two Months Ended February 28,			For the Year Ended December 31,
	2011			2010			2010			2009			2008			2007
	(In thousands, except for per share amounts)
Statement of Operations Data:
Net income (loss)	$	(43,390	)	$	(25,464	)	$	(266,293	)	$	(46,260	)	$	(47,096	)	$	33,799
Interest income	(63		)	(139		)	—			(11		)	(3,040		)	(12,432		)
Interest expense (a)(b)	24,186			8,274			1,422			14,697			5,077			16,240
Income tax expense (benefit)	536			(29		)	(626		)	(8,956		)	(7,472		)	(477		)
Depreciation	23,994			9,792			2,795			14,366			14,522			12,578
Amortization	791			—			—			—			—			—
EBITDA	$	6,054		$	(7,566	)	$	(262,702	)	$	(26,164	)	$	(38,009	)	$	49,708
Loss on the early extinguishment of debt	$	10,038		$	—		$	—		$	—		$	—		$	—
Loss related to auction rate securities	—			—			—			—			31,601			—
Impairment of plant development costs	—			—			—			—			1,557			—
Reorganization items	—			—			20,282			32,440			—			—
CEO retirement	1,054			—			—			—			—			—
E-Biofuels settlement	(1,572		)	—			—			—			—			—
Union Tank settlement	(90		)	—			—			—			—			—
Gain due to plan effects	—			—			(136,574		)	—			—			—
Loss due to fresh-start accounting adjustments	—			—			387,655			—			—			—
Stock-based compensation	5,434			7,784			277			2,536			5,729			7,205
Loss on available for sale securities	510			1,990			—			—			—			—
Gain on resolution of bankruptcy issues	—			(873		)	—			—			—			—
Adjusted EBITDA	$	21,428		$	1,335		$	8,938		$	8,812		$	878		$	56,913

(a)Interest capitalized during construction was $4.2 million for the year ended December 31, 2011, $6.2 million for the ten months ended December 31, 2010, and $0 for the two months ended February 28, 2010.

(b)Contractual interest expense not recorded was $5.0 million for the two months ended February 28, 2010. We had no unrecorded interest expense for the year ended December 31, 2011, and the ten months ended December 31, 2010.

38

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

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

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

Business Summary

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

Recent Developments

2011 Significant Events

On January 21, 2011, we redeemed our $155.0 million 13% senior secured notes due 2015 (the “Notes”) at a redemption price of 105% of the principal amount, plus accrued and unpaid interest.

On February 28, 2011, we amended our revolving credit facility (the “Revolving Facility”) with PNC Bank National Association (“PNC”), which increased our maximum loan amount from $20.0 million to $30.0 million.  The amendment required us to provide cash as security for all outstanding and undrawn letters of credit but allowed us to utilize the existing $5.0 million pledged to PNC as part of the cash required to secure our letters of credit.

In connection with the New Revolving Facility described below, the rights and obligations of the lenders under the Revolving Facility have been assigned from PNC to Wells Fargo, and we terminated the Revolving Facility.

On April 7, 2011, we entered into an incremental amendment (the “Incremental Amendment”) with Citibank, N.A., as administrative agent for the lenders under the senior secured term loan agreement, dated as of December 22, 2010 (the “Term Loan Agreement”), and Macquarie Bank Limited, as lender (“Macquarie”), to the Term Loan Agreement.  Pursuant to the Incremental Amendment, Macquarie loaned us an aggregate principal amount equal to $25.0 million, net of $1.3 million in fees.  The loan under the Incremental Amendment has substantially the same terms as the existing loans under the Term Loan Agreement, including seniority, ranking in right of payment and of security, maturity date, applicable margin and interest rate floor.  We continue to be subject to all other terms and restrictions contained in the original Term Loan Agreement.

On April 27, 2011, we temporarily shut down our dry mill plant in Aurora, Nebraska to make some improvements to the fermentation process at the facility.  This work was completed by the third week of May 2011, and we began grinding corn again during the week of July 25, 2011.

39

On May 13, 2011, we commenced a pro-rata distribution, consisting of 19,414 shares of common stock, to holders of our pre-petition notes and to holders of allowed general unsecured claims, with 9,806 shares distributed to holders of pre-petition notes and 9,608 shares distributed to holders of allowed general unsecured claims.

On July 20, 2011, we and each of our subsidiaries, as co-borrowers (collectively, the “Borrowers”), entered into a revolving credit facility (the “New Revolving Facility”) with the lenders party thereto (the “Lenders”), and Wells Fargo Capital Finance, LLC, as Lender and as agent for the Lenders (in such capacity, “Wells Fargo”) (the “New Revolving Facility Agreement”), with a $50.0 million commitment.  The New Revolving Facility has a borrowing base that is principally supported by accounts receivable and inventory.  At December 31, 2011, we had $20.1 million available under the New Revolving Facility Agreement.  Future borrowings under the New Revolving Facility will be used for general corporate purposes.  In connection with the New Revolving Facility, the rights and obligations of the lenders under the Revolving Facility were assigned from PNC to Wells Fargo.  We terminated our revolving credit agreement with PNC (the “Revolving Credit Agreement”) and paid a $0.6 million early termination fee.  In addition, we expensed $39 thousand in related unamortized debt issuance costs.  Both items are included in debt extinguishment costs for the year ended December 31, 2011.  We capitalized $2.9 million in debt issuance costs for the year ended December 31, 2011, related to the New Revolving Facility Agreement.  These costs will be amortized using the straight-line method over the term of the New Revolving Facility Agreement.  We recognized $0.3 million of expense in debt issuance costs related to the New Revolving Facility Agreement during the year ended December 31, 2011.

On July 20, 2011, we entered into an amendment (“Citi Amendment”) to the term loan agreement (the “Term Loan Agreement”) with the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent (the “Term Loan Agent”).  Under the terms of the Citi Amendment, the amount of indebtedness that we are permitted to incur under the New Revolving Facility (including bank products and hedging obligations) is capped at $58.0 million.  The Citi Amendment reduces our minimum liquidity covenant for 2012 from $25.0 million to $15.0 million. The Citi Amendment also includes certain technical amendments to permit the New Revolving Facility.

On August 19, 2011, Thomas Manuel (“Mr. Manuel”) retired as our Chief Executive Officer.  Mr. Manuel and the Company entered into a mutual release agreement, dated August 19, 2011 (the “Release Agreement”), whereby the parties acknowledged that Mr. Manuel would no longer serve as Chief Executive Officer of the Company.  Mr. Manuel also retired from his position as a director of the Company, effective the same date.  Pursuant to the terms of the Release Agreement, Mr. Manuel received, among other things, (i) a separation payment of $1,040,000; (ii) the vesting of his outstanding equity awards, effective as of August 19, 2011; and (iii) his outstanding restricted stock units.  Mr. Manuel’s options and hybrid equity units will remain exercisable until August 19, 2012.

On September 30, 2011, the Company settled with Union Tank Car Company (“Union Tank”).  The settlement related to a claim filed by Union Tank on September 3, 2009, against the Company.  The claim was filed with the U.S. Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) for a general unsecured claim in the amount of $82.6 million for certain estimated end charges including railcar cleaning costs and unpaid rental payments for leased railcars.  Union Tank also filed an administrative claim against the Company in the amount of $0.1 million for the alleged use of railcars after the effective date of the rejection of the leases for such railcars.  The Company disputed both of these claims.  The Court ruled that the claim shall be allowed in the amount of $27.6 million.  Partial distribution of shares on account was made October 31, 2011 in accordance with the terms of the First Amended Joint Plan of Reorganization under Chapter 11 of Title 11 of the U.S. Code (as modified, the “Plan”) and at such time as the distribution was made to other holders of claims in classes five and six that were allowed as of September 30, 2011.  As a result of the settlement, the Company reversed the related reserve for this matter of $0.1 million through other non-operating income on the statement of operations.

40

On October 31, 2011, we commenced a pro-rata distribution of shares related to a settlement with E-Biofuels, LLC (“E-Biofuels”) on July 6, 2011.  In 2009, we initiated a civil action against E-Biofuels related to breach of agreement, and asked for not less than $3.0 million in compensation.  This suit was later transferred to the Bankruptcy Court.  Under the terms of the settlement, we received $0.2 million in cash and 425,000 shares of Imperial Petroleum, Inc. (E-Biofuels’ parent company) stock.  The stock was valued at $0.7 million on the date of receipt of July 6, 2011.  We also had previously recorded a liability related to tax credits of $0.7 million which was relieved by the settlement.  The net gain of $1.6 million is included in other non-operating income on the statement of operations.  The stock was booked as short-term investments which are classified as available for sale securities on the balance sheet.  For the year ended December 31, 2011, we booked a loss on available for sale securities of $0.5 million related to the decrease in the current trading price of the stock which is included in other non-operating income on the statement of operations.  The pro-rata share distribution on October 31, 2011, consisted of 774,425 shares of common stock, to holders of our pre-petition notes and to holders of allowed general unsecured claims, with 399,993 shares distributed to holders of pre-petition notes and 374,432 shares distributed to holders of allowed general unsecured claims.  Approximately 0.4 million shares of common stock are reserved for future distributions to these holders.

Business Environment

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

Commodity Pricing

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

Ethanol. During 2011, ethanol prices did not follow corn prices as closely as they did in 2010. At December 31, 2011, we had future contracts for delivery of ethanol totaling 62.0 million gallons through September 30, 2012, of which 3.9 million gallons were based on fixed-price contracts and 58.1 million were at spot prices using Platts and OPIS indices.

Corn.  In 2011, corn prices rose steadily during the first half of the year, followed by a decline in the second half, with an overall increase in price of 2.8% for the year.  We continue to believe that corn prices are likely to remain above historical levels for the foreseeable future.

We continuously purchase corn for physical delivery from suppliers using forward purchase contracts in order to assure supply. As we do this, we have in the past often shorted a like amount of Chicago Board of Trade (“CBOT”) corn futures with similar dates to lock in the basis differential. We have also occasionally used CBOT futures contracts to lock in the price of corn by taking long positions in CBOT contracts in order to reduce our risk of price increases. Exchange traded forward contracts for commodities are marked to market each period. Our forward physical purchases of corn are not marked to market.  At December 31, 2011, we had fixed the price of 1.2 million bushels of corn through February 2012 and we had future contracts to sell 45 thousand bushels of corn.

Natural Gas. Natural gas is an important input in our ethanol and co-product production process. We use natural gas primarily to dry distillers grains for storage and transportation over longer distances. This allows us to market distillers grains to broader livestock markets in the U.S. The price fluctuation in natural gas prices over 2011, based on the New York Mercantile Exchange daily futures data, has ranged from a high of $4.98 per MMBtu on June 9, 2011, to a low of $2.96 per MMBtu at the end of December 2011.  Our current natural gas usage is approximately 550,000 MMBtu’s per month.

41

Supply and Demand

According to the Renewable Fuels Association (“RFA”), the annual corn-based ethanol production capacity of U.S. plants currently in operation and those under construction is approximately 15.1 billion gallons annually (plants currently in operation have a capacity of approximately 14.9 billion gallons annually while plants under construction have an approximate capacity of 0.2 billion gallons annually). The RFA estimated 2011 annual domestic ethanol production of 13.9 billion gallons.  In 2011, the U.S. exported approximately 1.2 billion gallons for the year.  Ethanol produced in the U.S. competes with sugar-based ethanol produced in Brazil. This domestic production capacity, along with imports, may cause supply to exceed demand. If additional demand for ethanol is not created, either through additions to discretionary blending (through increased penetration rates in areas that blend ethanol today or through the establishment of new markets where little or no ethanol is blended today), through exports, or through additional state level mandates, the excess supply may cause ethanol gross margins to decrease, perhaps substantially.

Ethanol Supports

We receive significant benefits from federal and state statutes, regulations and programs. Notwithstanding the above, changes to federal and state statutes, regulations or programs could have an adverse effect on our business. Recent federal legislation, however, has been of benefit to the ethanol industry. In December 2007, The Energy Independence and Security Act of 2007 (“EISA”) was passed which contained a new increased Renewable Fuel Standards (“RFS”). The new RFS requires fuel refiners to use a certain minimum amount of renewable fuels, which will rise from 12.95 billion gallons in 2010, of which 12.0 billion gallons relates to corn based ethanol, to 36.0 billion gallons, of which 15.0 billion gallons relates to corn based ethanol, by 2022. Ethanol previously benefited from an excise tax credit of $0.45 per ethanol gallon (prior to January 1, 2009, the excise tax credit was $0.51 per gallon). This excise tax credit provided incentives for blenders and refiners to blend ethanol with gasoline.  This credit expired on December 31, 2011.

Cancellation of indebtedness income

We recognized income from the cancellation of indebtedness (“COD”) when we emerged from bankruptcy to the extent that debt was discharged for consideration to a creditor for an amount that is less than the amount of such debt. For these purposes consideration includes the amount of cash and the fair market value of property, including stock of the debtor, transferred to the creditor. The amount of COD income, in general, is the excess of (a) the adjusted issue price of the indebtedness satisfied, over (b) the sum of the amount of cash paid and the fair market value of any new consideration (including the new stock of the Company following emergence from bankruptcy) given in satisfaction of the cancelled debt. The amount of COD income we realized in 2010 was $52 million for U.S. federal income tax purposes.

To the extent of COD income, we were required to reduce certain of our tax attributes (principally, the current year tax losses, capital loss carryforward and the tax basis in our assets) in the year following emergence. These attribute reductions were made on January 1, 2011. Among other things, this had the effect of reducing our future depreciation deductions.

Section 382 limitations

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

42

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

Financial Statement Overview

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

Fresh-Start Accounting

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

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

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

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

43

Variability of Gross Profit

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

Our most volatile manufacturing costs are natural gas and corn.  Since both natural gas and ethanol are energy-related products, there has been significant, although not perfect, correlation between their market prices.  As a result, at times when natural gas prices had increased, thereby increasing our costs, ethanol prices have typically increased, thereby increasing our revenues and offsetting some of the impact on our results of operations.  See “Item 1A — Risk Factors” for additional information.

Conversion Costs

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

Summary of Critical Accounting Policies

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

Revenue Recognition

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

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

The majority of sales are based upon a delivered price, which includes a cost for freight.  In such cases, the sales price, including the cost of delivery, is invoiced and included in revenue.  If title transfers at the shipment origination point, the customer generally is responsible for freight costs, and we do not recognize such freight costs in the financial statements.

44

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 and 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 price risk.  Derivatives used are primarily commodity futures contracts, swaps and option contracts.

We apply the provisions of ASC 815, Derivatives and Hedging (“ASC 815”), for our derivatives.  At December 31, 2011, our futures contracts were not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income.  Such derivative instruments are recorded at fair value, and are included in “Prepaid expenses and other current assets” on our consolidated balance sheets.

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

Income Taxes

Under ASC 740, Income Taxes, deferred tax liabilities and assets are recorded for the expected future tax consequences of events that have been recognized in our financial statements or tax returns.  Property, plant and equipment, stock-based compensation expense, benefit obligations, debt issuance costs and original issue discount are the primary sources of these temporary differences.  Deferred income taxes also include net operating loss and capital loss carryforwards.  The Company establishes valuation allowances to reduce deferred tax assets to amounts it believes are realizable. These valuation allowances and contingency reserves are adjusted based upon changing facts and circumstances.

Pension and Postretirement Benefit Costs

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

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

45

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.

Share-Based Compensation Expense

We account for our share-based compensation in accordance with ASC 718, Compensation — Stock Compensation (“ASC 718”), which requires measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including stock options, based on fair values.  Share-based compensation expense recognized is based on the value of the portion of share-based payment awards that is ultimately expected to vest.  We attribute the value of share-based compensation to expense over the periods of requisite service using the straight-line method.

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

Results of Operations

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

Overview

For the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, we generated net losses of $43.4 million, $25.5 million, $266.3 million, and $46.3 million, respectively. The loss for the year ended December 31, 2011, is primarily due to increased corn costs relative to ethanol values and elevated conversion costs at the Mt. Vernon facility due to start-up inefficiencies, as well as a $9.4 million loss incurred on the early extinguishment of the Notes. Contributing to the loss in the ten months ended December 31, 2010, was higher selling, general and administrative (“SG&A”) expenses associated with the hiring of new executive management in connection with our emergence from bankruptcy.  The loss in the two months ended February 28, 2010, is primarily attributable to adjustments of $387.7 million required to report assets and liabilities at fair value under fresh-start accounting and $20.3 million of reorganization items resulting from the Company’s Chapter 11 bankruptcy filing, which were offset by a gain due to plan effects of $136.6 million.  The 2009 net loss of $46.3 million is primarily attributable to $32.4 million in reorganization items.

46

Total gallons of ethanol marketed and distributed were as follows (in millions of gallons):

	Successor			Predecessor
	For the Year Ended December 31,	For the Ten  Months Ended  December 31,		For the Two  Months Ended February 28,		For the Year  Ended December 31,
	2011	2010		2010		2009
Equity production	248.7	154.4		32.0		197.5
Marketing alliances	—	—		—		30.9
Purchase / resale	6.7	1.0		0.2		35.5
Decrease (increase) in inventory	2.1	(2.9	)	(0.7	)	13.6
Total gallons	257.5	152.5		31.5		277.5

The decrease in marketing alliances and purchase/resale is a result of the termination of our marketing alliances beginning in late 2008, as well as our efforts to scale back our purchase/resale program beginning in the first quarter of 2009.

Year Ended December 31, 2011, Compared with the Ten Months Ended December 31, 2010 and the Two Months Ended February 28, 2010

On March 15, 2010, we emerged from bankruptcy and implemented fresh-start accounting in accordance with ASC 852 using a Convenience Date of February 28, 2010. Therefore, the consolidated financial statements prior to March 1, 2010, reflect results based upon the historical cost basis of the Company while the post-emergence consolidated financial statements reflect the new basis of accounting incorporating the fair value adjustments made in recording the effects of fresh-start reporting. Therefore, the post-emergence periods are not comparable to the pre-emergence periods. As a result of the application of fresh start accounting, our consolidated financial statements prior to and including February 28, 2010 represent the operations of our pre-reorganization predecessor company and are presented separately from the consolidated financial statements of our post-organization successor company.

	Successor						Predecessor
	For the Year Ended December 31,			For the Ten Months Ended  December 31,			For the Two Months Ended February 28,
	2011			2010			2010
	(In millions)
Statement of Operations data:
Net sales	$	887.6		$	370.6		$	77.7
Cost of goods sold	(857.4		)	(349.8		)	(66.7		)
Gross profit	30.2			20.8			11.0
Selling, general and administrative expenses	(32.7		)	(34.0		)	(4.6		)
Start-up activities	—			(1.2		)	—
Other operating expense	(3.3		)	(1.7		)	(0.5		)
Operating income (loss)	(5.8		)	(16.1		)	5.9
Other (expense) income:
Interest expense	(24.2		)	(8.3		)	(1.4		)
(Loss) gain on derivative transactions	(4.4		)	0.6			—
Loss on available-for-sale securities	(0.5		)	(2.0		)	—
Loss on early extinguishment of debt	(10.0		)	—			—
Other non-operating income	2.0			0.3			—
Reorganization items	—			—			(20.3		)
Gain due to Plan effects	—			—			136.6
Loss due to fresh start accounting adjustments	—			—			(387.7		)
Income tax (expense) benefit	(0.5		)	—			0.6
Net loss	$	(43.4	)	$	(25.5	)	$	(266.3	)

47

Net sales were generated from the following products:

	Successor				Predecessor
	For the Year Ended December 31,		For the Ten Months Ended December 31,		For the Two Months Ended February 28,
	2011		2010		2010
Ethanol	$	680.2	$	284.8	$	60.1
By-Products	207.4		85.8		17.6
Total	$	887.6	$	370.6	$	77.7

The overall increase in net sales from the ten months ended December 31, 2010, and two months ended February 28, 2010, to the year ended December 31, 2011, is primarily the result of increased sales volume from our increased production, as well as an increase in the sales price per gallon of ethanol.  During the year ended December 31, 2011, we produced 248.7 million gallons of ethanol compared to 154.4 million gallons and 32.0 million gallons of ethanol, respectively, during the ten months ended December 31, 2010, and two months ended February 28, 2010.  We marketed and sold 257.5 million gallons of ethanol during the year ended December 31, 2011, for an average sales price of $2.64 per gallon compared to 152.5 million gallons for average sales price of $1.87 per gallon during the ten months ended December 31, 2010, and 31.5 million gallons at an average sales price of $1.91 per gallon during the two months ended February 28, 2010.

The increase in by-product revenues is primarily a result of an increase in the price per ton sold, as well as an increase in the volume sold.  We sold 1.2 million tons during the year ended December 31, 2011, for an average price of $179.88 per ton compared to 778.2 thousand tons during the ten months ended December 31, 2010, for an average price of $110.22 per ton and 154.1 thousand tons during the two months ended February 28, 2010, for an average price of $114.12 per ton. By-product revenues, as a percentage of corn costs, fell to 32.3% during the year ended December 31, 2011, compared to 34.5% and 39.8%, respectively, during the ten months ended December 31, 2010, and two months ended February 28, 2010.  Co-products sold by the dry mill process have less value historically than those sold by the wet mill process.  As a result of the addition of the Mt. Vernon dry mill, our overall product mix between wet and dry co-products produced changed from 58% higher value wet mill products and 42% lower value dry mill products during the year ended December 31, 2010, to roughly 45% higher value wet mill products and 55% lower value dry mill products during the year ended December 31, 2011.

Cost of goods sold consists of corn costs, conversion costs (the cost to produce ethanol at our own facilities), the cost of purchased ethanol, the cost changes in our inventory, freight and logistics to ship ethanol and co-products, and depreciation and amortization, which are discussed in detail below.

	Successor								Predecessor
	For the Year Ended				For the Ten Months Ended				For the Two Months Ended
	December 31,2011		Percentage  of Net sales		December 31,2010		Percentage  of Net sales		February 28, 2010		Percentage  of Net sales
Cost of goods sold	$	857.4	96.6	%	$	349.8	94.4	%	$	66.7	85.8	%

The increase in cost of goods sold from the ten months ended December 31, 2010, and two months ended February 28, 2010, compared to the year ended December 31, 2011, is principally the result of higher

48

volumes of ethanol produced and sold during the year ended December 31, 2011, as well as an increase in corn costs. The increase in cost of goods sold as a percentage of net sales is principally the result of increased corn costs, freight costs and depreciation which are discussed below.

Production costs include corn costs, conversion costs, and depreciation and amortization, which are discussed below.

Corn costs for the year ended December 31, 2011, ten months ended December 31, 2010, and two months ended February 28, 2010, were $642.0 million, $248.9 million, and $44.2 million, respectively.  The increase in corn costs is due to an increase in the number of bushels used in production, as well as an increase in the price per bushel.  We used 93.7 million bushels of corn in production during the year ended December 31, 2011, compared to 59.2 million bushels and 12.1 million bushels, respectively, used during the ten months ended December 31, 2010, and two months ended February 28, 2010. Additionally, during the year ended December 31, 2011, corn used in production was approximately $6.85 per bushel compared to $4.21 per bushel for the ten months ended December 31, 2010, and $3.66 per bushel for the two months ended February 28, 2010.  Our average corn costs during the year ended December 31, 2011, were slightly higher than the CBOT average price of $6.80 during the same period.

Conversion costs for the year ended December 31, 2011, ten months ended December 31, 2010, and two months ended February 28, 2010 were as follows:

	Successor				Predecessor
	For the Year Ended		For the Ten Months Ended		For the Two Months Ended
	December 31,2011		December 31,2010		February 28,2010
	(In millions)
Utilities	$	59.0	$	30.1	$	7.6
Salary and benefits	25.2		17.8		3.3
Materials and supplies	27.9		17.1		3.2
Denaturant	12.6		6.2		1.4
Outside services	12.6		5.4		0.5
Other	1.2		2.2		0.6
	$	138.5	$	78.8	$	16.6

The increases in utilities, materials and supplies, and outside services are primarily attributable to the start-up of our Mt. Vernon facility.  Conversion costs per gallon were $0.56 for the year ended December 31, 2011, $0.51 for the ten months ended December 31, 2010, and $0.52 for the two months ended February 28, 2010.  Inefficiencies from lower operating capacity at the Mt. Vernon facility contributed approximately $0.06 per gallon to the total conversion costs for 2011.

Depreciation, amortization and infrastructure expenses in cost of goods sold for the year ended December 31, 2011, ten months ended December 31, 2010, and two months ended February 28, 2010, was $23.6 million, $8.9 million and $2.3 million, respectively.  Depreciation expense increased primarily as a result of the start-up of the Mt. Vernon facility.

Purchased ethanol is included in our cost of goods sold.  For the year ended December 31, 2011, ten months ended December 31, 2010, and two months ended February 28, 2010, we purchased 6.7 million gallons, 1.0 million gallons and 0.2 million gallons, respectively.  Purchased ethanol totaled $18.5 million, $1.7 million, and $0.4 million, respectively, for the year ended December 31, 2011, ten months ended December 31, 2010, and two months ended February 28, 2010.  The average cost per gallon purchased was $2.77 during the year ended December 31, 2011, compared to $1.69 during the ten months ended December 31, 2010, and $1.88 during the two months ended February 28, 2010.  This increase is consistent with the overall increase in ethanol spot prices using OPIS indices to an average price of $2.63 per gallon during the

49

year ended December 31, 2011, from an average price of $1.85 per gallon during the year ended December 31, 2010.

As stated above, cost of goods sold includes the cost changes in our inventory. Our direct materials, labor and overhead costs in the condensed consolidated statements of operations are based on production amounts.  The change in inventory included in cost of goods sold adjusts our statements of operations from cost of production to cost of sales.  During the year ended December 31, 2011, changes in inventory resulted in a reduction in cost of goods sold of $1.4 million compared to a reduction in cost of goods sold of $8.1 million in the ten months ended December 31, 2010, and expense of $0.2 million in the two months ended February 28, 2010.  The expense for year ended December 31, 2011 was primarily the result of the quantity and value of ethanol produced and sold during the year ended December 31, 2011.

Freight and logistics costs for the year ended December 31, 2011, were $34.0 million compared to $21.1 million and $3.4 million, respectively, for the ten months ended December 31, 2010 and two months ended February 28, 2010.  During the year ended December 31, 2011, we marketed and distributed approximately 257.5 million gallons of ethanol compared to 152.5 million gallons and 31.5 million gallons, respectively, during the ten months ended December 31, 2010, and two months ended February 28, 2010.  On a per gallon basis, freight and logistics costs were $0.13 per gallon, $0.14 per gallon and $0.11 per gallon, respectively, for the year ended December 31, 2011, ten months ended December 31, 2010, and two months ended February 28, 2010.

The average ethanol sales price for the year ended December 31, 2011, was $2.64 compared to $1.87 for the ten months ended December 31, 2010.  This represents a 41% increase in sales price per gallon.  The average cost of corn bushels used was $6.85 for the year ended December 31, 2011, compared to $4.21 for the ten months ended December 31, 2010.  This represents a 63% increase in cost per bushel used.

	Successor						Predecessor
	For the Year Ended			For the Ten Months Ended			For the Two Months Ended
	December 31,2011			December 31,2010			February 28,2010
Average sales price per gallon of ethanol	$	2.64		$	1.87		$	1.91
Average purchase price per bushel of corn used	$	6.85		$	4.21		$	3.66
Co-product revenue as a percentage of corn costs	32.3		%	34.5		%	39.8		%

SG&A expenses were $32.7 million, $34.0 million, and $4.6 million, respectively, for the year ended December 31, 2011, ten months ended December 31, 2010, and two months ended February 28, 2010.  SG&A expenses in the year ended December 31, 2011, were primarily comprised of $9.7 million of salary and benefits expense, $5.4 million of stock compensation expense, $6.5 million of outside services expenses, $1.9 million of depreciation expense, $1.6 million of expense related to materials, and $7.6 million of other expenses.  Included in the year ended December 31, 2011, totals are carrying costs related to our Canton and Aurora West facilities of $4.2 million.  SG&A expenses for the ten months ended December 31, 2010, were primarily comprised of $9.1 million of salary and benefits expense, $7.8 million of stock compensation expense, $10.4 million of outside services expenses, and $6.7 million of other expenses. SG&A expenses in the two months ended February 28, 2010, were primarily comprised of $0.8 million of salary and benefits expense, $0.2 million of stock compensation expense, $1.7 million of outside services expenses, and $1.9 million of other expenses.

Interest expense for the year ended December 31, 2011, ten months ended December 31, 2010, and two months ended February 28, 2010, was $24.2 million, $8.3 million, and $1.4 million, respectively.  Interest expense for the year ended December 31, 2011, includes $23.2 million related to the Term Loan Facility (as defined below), $1.1 million related to the Notes, $1.1 million of other interest expense, and $3.1 million of amortization of deferred financing fees and original issue discount, reduced by capitalized interest of $4.2 million. Interest expense for the ten months ended December 31, 2010, includes $13.2

50

million of interest expense related to the Notes and $1.3 million of other interest expense, reduced by capitalized interest of $6.2 million. Interest expense for the two months ended February 28, 2010, includes pre-petition amended secured revolving credit facility interest expense of $0.6 million, interest expense on our debtor-in-possession debt facility of $0.5 million, and $0.3 million of amortization of deferred financing fees.

Loss on derivative transactions, net for the year ended December 31, 2011, includes $4.4 million of net realized and unrealized losses on corn and ethanol derivative contracts versus net realized and unrealized gains in the ten months ended December, 2010, of $0.6 million. We recorded no realized or unrealized gains or losses on derivative contracts during the two months ended February 28, 2010. We do not mark to market forward physical contracts to purchase corn or sell ethanol as we account for these transactions as normal purchases and sales under ASC 815.

On January 21, 2011, we redeemed our $155.0 million Notes at a redemption price of 105% of the principal amount, plus accrued and unpaid interest.  In connection with the redemption, we recognized a $9.4 million loss on the early extinguishment of debt.

Other non-operating income of $1.6 million for the year ended December 31, 2011, is primarily related to gains on legal settlements with E-BioFuels and Union Tank.  Other non-operating income of $0.2 million for the year ended December 31, 2010, is primarily the result of adjustments of various valuation reserves.

During the two months ended February 28, 2010, we recognized reorganization expenses of $20.3 million, of which $9.6 million related to provision for rejected executory contracts and other accruals, $8.8 million related to professional fees directly related to reorganization and $1.9 million related to other expenses.

The loss due to fresh start accounting adjustments of $387.7 million in the two months ended February 28, 2010, consisted of adjustments required to report assets and liabilities upon emergence from bankruptcy at fair value.  See our discussion of fresh start accounting above.  Gain due to plan effects in the two months ended February 28, 2010, of $136.6 million related to implementation of our Plan and consisted of $193.5 million of liabilities subject to compromise which were discharged upon emergence less $5.8 million of unamortized debt issuance costs on our pre-petition notes, $1.6 million related to the write-off of predecessor prepaid directors and officer insurance, $5.3 million of successor-based professional fees awarded under the Plan, $42.6 million related to loss on shares granted in connection with the Notes and $1.6 million of other miscellaneous costs.

Our tax rate for the year ended December 31, 2011, was (1.3%) of pre-tax loss compared to a tax benefit rate for the ten months ended December 31, 2010, of 0.1% of pre-tax loss and a tax benefit rate for the two months ended February 28, 2010, of 0.2% of pre-tax loss.  Our effective tax rate differs from the statutory tax rate primarily due to valuation allowances on our deferred taxes.

Ten Months Ended December 31, 2010, and Two Months Ended February 28, 2010, Compared with the Year ended December 31, 2009

On March 15, 2010, we emerged from bankruptcy and implemented fresh-start accounting in accordance with ASC 852 using a Convenience Date of February 28, 2010. Therefore, the consolidated financial statements prior to March 1, 2010, reflect results based upon the historical cost basis of the Company while the post-emergence consolidated financial statements reflect the new basis of accounting incorporating the fair value adjustments made in recording the effects of fresh-start reporting. Therefore, the post-emergence periods are not comparable to the pre-emergence periods. As a result of the application of fresh start accounting, our consolidated financial statements prior to and including February 28, 2010,

51

represent the operations of our pre-reorganization predecessor company and are presented separately from the consolidated financial statements of our post-organization successor company.

	Successor			Predecessor
	For the Ten Months Ended			For the Two Months Ended			For theYear Ended
	December 31,2010			February 28,2010			December 31,2009
	(In millions)
Statement of Operations data:
Net sales	$	370.6		$	77.7		$	594.6
Cost of goods sold	(349.8		)	(66.7		)	(585.9		)
Gross profit	20.8			11.0			8.7
Selling, general and administrative expenses	(34.0		)	(4.6		)	(26.7		)
Start-up activities	(1.2		)	—			—
Other operating expense	(1.7		)	(0.5		)	(1.5		)
Operating income (loss)	(16.1		)	5.9			(19.5		)
Other (expense) income:
Interest expense	(8.3		)	(1.4		)	(14.7		)
Gain on derivative transactions	0.6			—			1.2
Loss on available-for-sale securities	(2.0		)	—			—
Other non-operating income	0.3			—			—
Reorganization items	—			(20.3		)	(32.4		)
Gain due to Plan effects	—			136.6			—
Loss due to fresh start accounting adjustments	—			(387.7		)	—
Income from termination of marketing agreements	—			—			10.2
Income tax benefit	—			0.6			8.9
Net loss	$	(25.5	)	$	(266.3	)	$	(46.3	)

Net sales were generated from the following products:

	Successor		Predecessor
	For the Ten Months Ended December 31,		For the Two Months Ended February 28,		For the Year Ended December 31,
	2010		2010		2009
	(In millions)
Ethanol	$	284.8	$	60.1	$	490.3
By-Products	85.8		17.6		97.9
Other	—		—		6.4
Total	$	370.6	$	77.7	$	594.6

The overall decrease in net sales from the year ended December 31, 2009, to the ten months ended December 31, 2010, and the two months ended February 28, 2010 of 24.6% is primarily the result of less supply available as we terminated our marketing alliance and significantly reduced our purchase/resale supply operations.  In addition, we experienced a decrease in our equity production during 2010 as a result of the temporary shutdown at our Nebraska facility during July and August.  The reduction in supply was partially offset by an increase in the average sales price of ethanol for the ten months ended December 31, 2010, and the two months ended February 28, 2010, as compared to the year ended December 31, 2009.  Ethanol prices averaged $1.87 per gallon during the ten months ended December 31, 2010, and $1.91 during the two months ended February 28, 2010, as compared to $1.75 per gallon during 2009.

The increase in by-product revenues is primarily a result of an increase in price, which was partially offset by lower sales volumes. We sold 778.2 thousand tons during the ten months ended December 31, 2010, and 154.1 million tons during the two months ended February 28, 2010, versus 1.1 million tons in

52

2009. By-product revenues, as a percentage of corn costs, rose to 34.5% during the ten months ended December 31, 2010, and 39.8% during the two months ended February 28, 2010, versus 34.1% in 2009.

Cost of goods sold consists of corn costs, conversion costs (the cost to produce ethanol at our own facilities), the cost of purchased ethanol, the cost changes in our inventory, freight and logistics to ship ethanol and co-products, and depreciation and amortization which are discussed in detail below.

	Successor				Predecessor
	For the Ten Months Ended				For the Two Months Ended				For theYear Ended
	December 31,2010		Percentage of Net sales		February 28,2010		Percentage of Net sales		December 31,2009		Percentage of Net sales
Cost of goods sold	$	349.8	94.4	%	$	66.7	85.8	%	$	585.9	98.5	%

The decrease in cost of goods sold from the year ended December 31, 2009, to the two months ended February 28, 2010, is principally the result of lower volumes of ethanol produced during 2010.  The decrease in cost of goods sold as a percentage of net sales from the year ended December 31, 2009, to the two months ended February 28, 2010, is principally the result of lower corn costs, freight costs, depreciation, and motor fuel taxes.  The increase in cost of goods sold as a percentage of net sales from the two months ended February 28, 2010, to the ten months ended December 31, 2010, is primarily due to increased corn costs.  During the two months ended February 28, 2010, corn used in production was approximately $3.66 per bushel while corn used in production during the ten months ended December 31, 2010, was approximated $4.21 per bushel.

Production costs include corn costs, conversion costs, and depreciation, which are discussed below.

Corn costs for the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, were $248.9 million, $44.2 million, and $287.1 million, respectively.  During 2010, the price per bushel of corn increased, which was offset in the ten months ended December 31, 2010, by lower volumes of corn purchased as a result of the Nebraska facility temporary shutdown.

Conversion costs for the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, were $78.8 million, $16.6 million, and $96.7 million, respectively.  Conversion costs for the ten months ended December 31, 2010, included $30.1 million of utilities, $17.8 million of salary and benefit expenses, $17.1 million of material and supply expenses, $6.2 million of denaturant, $5.4 million of outside services, and $2.2 million of other expenses.  Conversion costs for the two months ended February 28, 2010 include $7.6 million of utilities, $3.3 million of salary and benefit expenses, $3.2 million of material and supply expenses, $1.4 million of denaturant, $0.5 million of outside services, and $0.6 million of other expenses.  Conversion costs for the year ended December 31, 2009, included $39.0 million of utilities, $21.4 million of salary and benefit expenses, $20.5 million of material and supply expenses, $6.8 million of denaturant, $5.5 million of outside services, and $3.5 million of other expenses. Conversion costs per gallon were $0.51 for the ten months ended December 31, 2010, $0.52 for the two months ended February 28, 2010, and $0.49 for the year ended December 31, 2009.

Depreciation expense for the ten months ended December 31, 2010, and the two months ended February 28, 2010, was $8.9 million and $2.3 million, respectively.  Depreciation expense for the year ended December 31, 2009, was $14.4 million. Depreciation expense year over year decreased primarily as a result of the fresh start fair value adjustments, which reduced the cost basis of our depreciable assets.

Purchased ethanol is included in our cost of goods sold.  For the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, purchased ethanol

53

totaled $1.7 million, $0.4 million, and $138.5 million, respectively. The decrease resulted from the termination of our marketing alliance and scaled-back purchase/resale programs.

Freight and logistics costs for the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, were $21.1 million, $3.4 million, and $44.9 million, respectively.  On a per gallon basis, freight and logistics costs were $0.14 per gallon for the ten months ended December 31, 2010, $0.11 per gallon for the two months ended February 28, 2010, and $0.16 per gallon for the year ended December 31, 2009. The decrease in total dollars and the total dollars per gallon in each period during 2010 as compared to the year ended December 31, 2009, is the result of lower volumes shipped, the termination of fixed price terminal obligations and lower costs for leased railcars.

The average sales price per gallon of ethanol was $1.75 during the year ended December 31, 2009, $1.91 during the two months ended February 28, 2010, and $1.87 during the ten months ended December 31, 2010.  Co-product revenue as a percentage of corn costs was 34.5% for the ten months ended December 31, 2010, 39.8% for the two months ended February 28, 2010, and 34.1% for the year ended December 31, 2009.

SG&A expenses were $34.0 million, $4.6 million, and $26.7 million, respectively, for the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009.  SG&A expenses in the ten months ended December 31, 2010, were primarily comprised of $16.9 million of salary and benefits expense, $10.4 million of outside services expenses, and $6.7 million of other expenses.  SG&A expenses in the two months ended February 28, 2010, were primarily comprised of $1.0 million of salary and benefits expense, $1.7 million of outside services expenses, and $1.9 million of other expenses.  SG&A expenses for the year ended December 31, 2009, were primarily comprised of $9.0 million of salary and benefits expense, $9.5 million of outside services expenses, and $8.2 million of other expenses. Outside services expenses in the ten months ended December 31, 2010, and the two months ended February 28, 2010, include professional fees that we incurred related to bankruptcy activities, which were included in reorganization expenses for the year ended December 31, 2009.

During the ten months ended December 31, 2010, the Company had $1.2 million of expenses related to the start up of the Mt. Vernon facility.  The Mt. Vernon facility ran at approximately 35.2% of nameplate capacity during the month of December 2010, producing approximately 3.2 million gallons of ethanol.

Interest expense for the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, was $8.3 million, $1.4 million, and $14.7 million, respectively.  Interest expense for the ten months ended December 31, 2010, includes $13.2 million of interest expense related to the Notes, $0.6 million related to the Term Loan Facility, $0.4 million of other interest expense, and $0.3 million of amortization of deferred financing fees, reduced by capitalized interest of $6.2 million. Interest expense for the two months ended February 28, 2010, includes pre-petition amended secured revolving credit facility interest expense of $0.6 million, interest expense on our debtor-in-possession debt facility of $0.5 million, and $0.3 million of amortization of deferred financing fees. Interest expense for the year ended December 31, 2009, includes $8.1 million of interest expense related to the Old Notes (contractual interest expense not recorded for the year ended December 31, 2009, was $21.9 million), pre-petition amended secured revolving credit facility interest expense of $2.5 million, interest expense on our debtor-in-possession debt facility of $1.8 million, and $2.3 million for amortization of deferred financing fees.

Gain (loss) on derivative transactions for the ten months ended December 31, 2010, includes $0.6 million of net realized  and unrealized gains on corn and ethanol derivative contracts versus net realized and unrealized gains in the year ended December 31, 2009, of $1.2 million. The Company recorded no realized or unrealized gains or losses on derivative contracts during the two months ended February 28, 2010. We do not mark to market forward physical contracts to purchase corn or sell ethanol as we account for these transactions as normal purchases and sales under ASC 815.

54

During the ten months ended December 31, 2010, we recorded a loss on the sale of our available for sale securities in Green Plains Renewable Energy, Inc. totaling $2.0 million.

During the two months ended February 28, 2010, we recognized reorganization expenses of $20.3 million as compared to $32.4 million during 2009.  The decrease of $12.1 million is primarily due to a decrease of $16.8 million in the provision for rejected executory contracts and leases, offset by an increase of $1.3 million related to professional fees directly related to the reorganization and an increase of $3.4 million for other miscellaneous bankruptcy related items.  The Company did not record reorganization expenses during the ten months ended December 31, 2010.

The loss due to fresh-start accounting adjustments of $387.7 million in the two months ended February 28, 2010, consisted of adjustments required to report assets and liabilities upon emergence from bankruptcy at fair value.  See our discussion of fresh start accounting above.  Gain due to plan effects in the two months ended February 28, 2010, of $136.6 million related to implementation of the Plan consisted of $193.5 million of liabilities subject to compromise which were discharged upon emergence less $5.8 million of unamortized debt issuance costs on our pre-petition notes (the “Old Notes”), $1.6 million related to the write-off of predecessor prepaid directors and officer insurance, $5.3 million of successor-based professional fees awarded under the Plan, $42.6 million related to loss on shares granted in connection with the Notes and $1.6 million of other miscellaneous costs.

As a result of our negotiations in 2009 with our former marketing alliance partners, we were able to obtain cash consideration totaling $10.2 million from those counterparties in exchange for the early termination of the marketing alliance agreements. Our alliance partners were willing to pay this amount because it freed them from their contractual obligations of selling ethanol to us on an exclusive basis.

The Company’s tax benefit rate for the ten months ended December 31, 2010, and the two months ended February 28, 2010, was 0.1% and 0.2%, respectively, of pre-tax loss.  The income tax benefit recorded in the ten months ended December 31, 2010, is net of a valuation allowance of $186.1 million and the income tax benefit recorded in the two months ended February 28, 2010, is net of a valuation allowance of $162.8 million. The valuation allowance recognized on our gross deferred tax assets reduced our deferred tax asset to the amount we believe is more likely than not to be realized.  The valuation allowance includes $150.7 million and $139.4 million, respectively, of reserve against the fresh start valuation adjustment for fixed assets for the ten months ended December 31, 2010, and the two months ended February 28, 2010.

Liquidity and Capital Resources

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

	December 31, 2011		December 31, 2010
	(In millions, except current ratio)
Cash and cash equivalents	$	36.1	$	34.5
Net working capital	$	70.6	$	72.9
Total debt (1)	$	216.3	$	348.7
Current ratio	3.12		1.37

(1)Concurrent with the closing of our Term Loan Agreement in December 2010, we irrevocably deposited in trust $164.8 million of the proceeds from the Term Loan Facility with the trustee for the Notes. These funds were sufficient to pay the redemption price for all $155.0 million aggregate principal amount of the Notes. We redeemed such Notes on January 21, 2011.

At emergence from bankruptcy on March 15, 2010, we obtained approximately $98.0 million of proceeds through the issuance of $105.0 million principal amount of the Notes and 1,710,000 shares of

55

common stock.  In addition, on August 19, 2010, we issued and sold an additional $50 million in aggregate principal amount of Notes, resulting in gross proceeds of approximately $51 million (excluding accrued interest on the Notes through the issue date).  Such Notes were redeemed on January 21, 2011, at a redemption price of 105% of the principal amount of $155.0 million, plus accrued and unpaid interest.

On December 22, 2010, we entered into the Term Loan Agreement (the “Term Loan Facility”) with the Term Loan Agent, the lenders party thereto, Citigroup Global Markets Inc. and Jefferies Finance LLC, as joint lead arrangers and joint book-runners, and Citibank, N.A. and Jefferies Finance LLC, as co-syndication agents.  Under the Term Loan Agreement, the lenders provided an aggregate principal amount of $200 million.  The Term Loan Facility was issued net of original issue discount of $8.0 million.

On April 7, 2011, we entered into the Incremental Amendment with Citibank, N.A., as administrative agent for the lenders under the Term Loan Agreement, and Macquarie, as lender, to the Term Loan Agreement.  Pursuant to the Incremental Amendment, Macquarie loaned to us an aggregate principal amount equal to $25.0 million, net of $1.3 million in fees.  The loan under the Incremental Amendment has substantially the same terms as the existing loans under the Term Loan Agreement, including seniority, ranking in right of payment and of security, maturity date, applicable margin and interest rate floor.  We continue to be subject to all other terms and restrictions contained in the original Term Loan Agreement.

On July 20, 2011, the Borrowers entered into the $50.0 million New Revolving Facility with the Lenders and Wells Fargo.  Future borrowings under the New Revolving Facility will be used for general corporate purposes.  In connection with the New Revolving Facility, the rights and obligations of the lenders under the Revolving Facility were assigned from PNC to Wells Fargo.  We terminated the Revolving Credit Agreement with PNC and paid a $0.6 million early termination fee.  In addition, we expensed $39 thousand in related unamortized debt issuance costs.  Both items are included in debt extinguishment costs for the year ended December 31, 2011.  We capitalized $2.9 million in debt issuance costs for the year ended December 31, 2011, related to the New Revolving Facility Agreement.  These costs will be amortized using the straight-line method over the term of the New Revolving Facility Agreement.  We recognized $0.3 million of expense in debt issuance costs related to the New Revolving Facility Agreement during the year ended December 31, 2011.

On July 20, 2011, Aventine entered into the Citi Amendment to the Term Loan Agreement with the lenders party thereto and the Term Loan Agent.  Under the terms of the Citi Amendment, the amount of indebtedness that Aventine is permitted to incur under the New Revolving Facility (including bank products and hedging obligations) is capped at $58.0 million.  The Citi Amendment modifies Aventine’s minimum liquidity covenant for 2012 reducing it from $25.0 million to $15.0 million. The Citi Amendment also includes certain technical amendments to permit the New Revolving Facility.

As of December 31, 2011, approximately 6.4 million of the 6.8 million new common equity shares reserved for distribution to general, unsecured claimholders under the Plan have been distributed.  However, because our ability to distribute shares held in reserve depends on resolving outstanding claims currently in dispute, it is difficult to predict the amount of each quarterly distribution, if any, or when all the remaining shares will be distributed.

Sources of Liquidity

Our principal sources of liquidity are cash and cash equivalents, cash provided by our borrowing facility, and cash provided by operations. If our future cash flow is insufficient to meet our debt obligations and commitments, we may be required to undertake alternative financing plans, such as: (i) refinancing or restructuring our debt, (ii) selling assets, (iii) reducing or delaying capital investments, or (iv) seeking to raise additional capital. There can be no assurance, however, that undertaking alternative financing plans would allow us to meet our debt obligations. Our inability to meet our debt obligations and commitments could lead to an event of default under the Term Loan Agreement or the New Revolving Facility. If an

56

event of default occurs under the Term Loan Agreement, then the Term Loan Facility may become immediately due and payable and the holders could accelerate repayment of the obligations under the Term Loan Facility or foreclose on the collateral granted to them. If an event of default occurs under the New Revolving Facility, then the lenders may terminate their commitments, accelerate repayment of the obligations, or foreclose on the collateral granted to them. In addition, an event of default under either of the Term Loan Agreement or the New Revolving Facility may lead to an event of default under the Term Loan Agreement or the New Revolving Facility, as the case may be, under certain circumstances.

In addition, our ability to execute on our growth strategy will be determined, in large part, by the availability of debt and equity capital, and we continuously evaluate our financing opportunities. Any decision regarding a financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors. Our ability to meet our liquidity requirements and execute on our growth strategy can be impacted by economic conditions outside of our control, such as the disruption in the capital and credit markets that occurred in 2008 and 2009, as well as commodity price volatility. We may be required to seek sources of capital earlier than anticipated, although the restrictions in our New Revolving Facility and Term Loan Agreement may impair our ability to access other sources of capital, and access to additional capital may not be available on terms acceptable to us or at all.

Cash and cash equivalents. Cash and cash equivalents increased by $1.6 million during the year ended December 31, 2011.  Cash and cash equivalents at December 31, 2011, and December 31, 2010, were $36.1 million and $34.5 million, respectively.

Cash available under our liquidity facility. Pursuant to the Plan, on the Effective Date, the Borrowers, entered into the $20.0 million Revolving Facility, which was increased to $30.0 million in February 2011. Amounts under the Revolving Facility could have been borrowed, repaid and reborrowed and all amounts outstanding were due and payable on March 15, 2013. The maximum amount outstanding under the Revolving Facility was limited by the amount of eligible receivables and eligible inventory of the Borrowers. The Revolving Facility contained mandatory prepayment requirements in certain circumstances upon the sale of certain collateral, subject to the ability to reborrow revolving advances. Termination of the Revolving Facility was subject to a prepayment premium if terminated more than 90 days prior to the third anniversary of the Revolving Facility.  This facility was terminated on July 20, 2011, and replaced by the New Revolving Facility with Wells Fargo.

On July 20, 2011, the Borrowers entered into the $50.0 million New Revolving Facility with Wells Fargo.  Future borrowings under the New Revolving Facility will be used for general corporate purposes.  In connection with the New Revolving Facility, the rights and obligations of the lenders under the Revolving Facility were assigned from PNC to Wells Fargo.  See Note 9 of Notes to our Consolidated Financial Statements for additional information regarding the New Revolving Facility.  We terminated the Revolving Credit Agreement with PNC and paid a $0.6 million early termination fee.  In addition, we expensed $39 thousand in related unamortized debt issuance costs.  Both items are included in debt extinguishment costs for the year ended December 31, 2011.  We capitalized $2.9 million in debt issuance costs for the year ended December 31, 2011, related to the New Revolving Facility Agreement.  These costs will be amortized using the straight-line method over the term of the New Revolving Facility Agreement. We recognized $0.3 million of expense in debt issuance costs related to the New Revolving Facility Agreement during the year ended December 31, 2011.

On December 22, 2010, we entered into the Term Loan Agreement. Under the Term Loan Agreement, the lenders provided us an aggregate principal amount $200.0 million Term Loan Facility. The proceeds of loans under the Term Loan Agreement of $200.0 million, net of $8.0 million of original issuance discount, were used (1) to redeem the Notes in the aggregate principal amount of $155.0 million at a redemption price of 105% of the principal amount, plus accrued and unpaid interest, (2) to pay related transaction costs, fees and expenses of $5.6 million, and (3) for general corporate purposes.

57

On April 7, 2011, we entered into the Incremental Amendment to the Term Loan Agreement, pursuant to which Macquarie loaned us an aggregate principal amount equal to $25.0 million, net of $1.3 million in fees.

On July 20, 2011, we entered into the Citi Amendment to the Term Loan Agreement with the lenders party thereto and the Term Loan Agent.  Under the terms of the Citi Amendment, the amount of indebtedness that we are permitted to incur under the New Revolving Facility (including bank products and hedging obligations) is capped at $58.0 million.  The Citi Amendment reduces our minimum liquidity covenant for 2012. The Citi Amendment also includes certain technical amendments to permit the New Revolving Facility.

Cash used in operations. Net cash used in operations was $8.5 million, $19.2 million and $11.7 million, respectively, for the year ended December 31, 2011, ten months ended December 31, 2010, and two months ended February 28, 2010. Cash used in operations during 2011 was primarily due to the start-up of our Mt. Vernon facility as well as operating issues at our Nebraska facility that were resolved at the summer shutdown.  Cash used in operations in 2010 was negatively impacted by significant operating losses incurred due to the start-up of the Mt. Vernon facility as well as higher SG&A expenses associated with the hiring of new executive management in connection with our emergence from bankruptcy, and payments of secured and priority claims.

Uses of Liquidity

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

Payments related to our debt and liquidity facility. During the year ended December 31, 2011, we used $2.2 million of cash to make required repayments of borrowings on our Term Loan Facility.  During the ten months ended December 31, 2010, we made no repayments on our borrowings.  During the two months ended February 28, 2010, we used $42.8 million of cash to make required repayments of borrowings on our prior revolving facility with JPMorgan Chase of $27.8 million and our debtor-in-possession debt facility of $15.0 million.

At December 31, 2011, the Company had $9.2 million in letters of credit outstanding.  Availability under the New Revolving Facility was $20.1 million at December 31, 2011.

Working capital.  Our net working capital position decreased by $2.3 million to $70.6 million at December 31, 2011, from $72.9 million at December 31, 2010.  Current assets decreased by $166.3 million to $103.9 million at December 31, 2011, from $270.2 million at December 31, 2010, primarily related to $164.8 of restricted cash at December 31, 2010, which was used in January 2011 to redeem the Notes.  Current liabilities decreased by $164.0 million to $33.3 million at December 31, 2011, from $197.3 million at December 31, 2010, primarily related to the $155.0 million principal amount of Notes, which were redeemed in January 2011.

Capital expenditures. During the year ended December 31, 2011, we spent approximately $23.3 million on capital projects. Of the $23.3 million spent during the year ended December 31, 2011, $6.6 million was spent on our capacity expansion project in Aurora, Nebraska, $5.9 million was spent on our capacity expansion project in Canton, Illinois and $6.3 million and $4.5 million were spent on projects in Pekin, Illinois and Mt. Vernon, Indiana, respectively.  During the ten months ended December 31, 2010, and the two months ended February 28, 2010, we spent $94.5 million and $2.1 million, respectively, on capital projects.  Of the $96.6 million spent during the year ended December 31, 2010, $79.7 million was spent on maintenance and environmental projects, and capacity expansion projects, and $16.9 million was spent on acquisition of the Canton facility.

58

We expect the Canton facility to become operational in the summer of 2012 and the Aurora West facility to become operational in mid 2012, subject to weather conditions, commodity prices, and the availability of working capital.  See “Liquidity Outlook” below.  At the Canton facility, we have made several improvements to reduce infections and improve yields.  We expect to have nominal additional expenditures to bring these plants on line in 2012.

Liquidity Outlook

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

Our principal sources of liquidity are cash and cash equivalents, cash provided by our borrowing facility, and cash provided by operations. At December 31, 2011, we had $36.1 million of cash and cash equivalents and $70.6 million in net working capital.  Additionally, at December 31, 2011, we had availability under the New Revolving Facility of approximately $20.1 million. We depend on the New Revolving Facility for future working capital needs. If there is an event of default by us under the New Revolving Facility that continues beyond any applicable cure period, resulting in amounts outstanding becoming immediately due and payable, or if our qualifying inventory and accounts receivable decline such that our borrowing base is limited, we may not have sufficient funds available to repay such borrowings or we may be unable to borrow a sufficient amount to fund our operations.  In the event that cash flows and borrowings under the New Revolving Facility are not sufficient to meet our cash requirements, we may be required to seek additional financing.

Our liquidity position is significantly influenced by our operating results, which in turn are substantially dependent on commodity prices, especially prices for corn, ethanol, natural gas, and unleaded gasoline. As a result, adverse commodity price movements adversely impact our liquidity. Often, movements in commodity prices are well correlated such that increases or decreases in commodities movements provide a predictable change in our liquidity.  However, in the last three years, there have been periods of time in which other economic factors cause a significant deterioration in commodity price correlations such that our ability to predict our liquidity level may be significantly diminished.  Accordingly, we can provide no assurance that the amounts of cash available from operations, together with the New Revolving Facility, will be sufficient to fund our operations.

Our principal uses of liquidity are payments related to our outstanding debt and liquidity facility, working capital, funding of operations, and capital expenditures. Under our Term Loan Agreement, we are required to maintain a minimum liquidity position of $15.0 million comprised of available cash and borrowing capacity under our New Revolving Facility throughout 2011 and 2012, and $25 million beginning in 2013.  Based on current commodity prices and market conditions, our liquidity forecast may indicate a need to defer start-up of our Aurora West facility and our Canton facility beyond 2012.  If we do not generate enough cash flow from operations to satisfy our principal uses of liquidity, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt, selling assets, reducing or delaying capital investments or raising additional capital. However, under our Term Loan Agreement, we are required to maintain a debt to total capitalization ratio of no greater than 0.65 to 1.0. There is no assurance that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations.

59

Despite the risks identified associated with our liquidity and our forecasted operating cash flows, we believe that we have sufficient liquidity through our cash and cash equivalents, cash from operations and borrowing capacity under our New Revolving Facility to meet our short-term and long-term normal recurring operating needs, debt service obligations, contingencies, and capital expenditures.  We also believe that the additional avenues available to preserve liquidity in the event of an industry or economic downturn are adequate to allow us to continue operations.

Financing

Term Loan Agreement

On December 22, 2010, we entered into the Term Loan Agreement, under which the lenders provided the aggregate principal amount of $200 million.  Also on December 22, 2010, we gave notice of redemption pursuant to the indenture dated as of the Effective Date among the Company, each of the Company’s direct and indirect wholly-owned subsidiaries, as guarantors, and Wilmington Trust FSB, as trustee and collateral agent, providing that it would redeem all $155.0 million aggregate principal amount of Notes at a redemption price of 105% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. Concurrently with the closing of the Term Loan Agreement, the Company irrevocably deposited in trust with the trustee for the Notes, $164.8 million of the proceeds from the Term Loan Facility, funds sufficient to pay the redemption price for all $155.0 million aggregate principal amount of the Notes. The Company redeemed such Notes on January 21, 2011.  In connection with the redemption, the Company paid $164.8 million, of which $155.0 million related to the principal amount of the Notes, $7.8 million related to a prepayment penalty on the Notes and $2.0 million related to interest on the Notes.  Accordingly, the Notes and the restricted cash for payment of the Notes were included in current liabilities and current assets, respectively, in the condensed consolidated balance sheet at December 31, 2010.

On April 7, 2011, we entered into the Incremental Amendment to the Term Loan Agreement, pursuant to which Macquarie loaned us an aggregate principal amount equal to $25.0 million, net of $1.3 million in fees.

On July 20, 2011, we entered into the Citi Amendment to the Term Loan Agreement with the lenders party thereto and the Term Loan Agent.  Under the terms of the Citi Amendment, the amount of indebtedness that we are permitted to incur under the New Revolving Facility (including bank products and hedging obligations) is capped at $58.0 million.  The Citi Amendment reduces our minimum liquidity covenant for 2012. The Citi Amendment also includes certain technical amendments to permit the New Revolving Facility.

New Revolving Facility

Pursuant to the Plan, on the Effective Date, the borrowers entered into the $20 million revolving facility, which was increased to $30.0 million in February 2011.  The amendment required the Company to provide cash as security for all outstanding and undrawn letters of credit but allowed the Company to utilize the existing $5.0 million pledged to PNC as part of the cash required to secure the letters of credit.

In addition to a borrowing base collateralization consisting primarily of accounts receivable and inventories, the Revolving Facility was collateralized by a $5.0 million restricted cash account less amounts used to collateralize outstanding, undrawn letters of credit.  The Company could not count the $5.0 million restricted cash account in its borrowing base.  The revolving facility was terminated on July 20, 2011.

60

On July 20, 2011, we entered into the $50.0 million New Revolving Facility with Wells Fargo. In connection with the New Revolving Facility, the rights and obligations of the lenders under the Revolving Facility were assigned from PNC to Wells Fargo and the facility was terminated.

Total liquidity at December 31, 2011, was $56.2 million, comprised of $36.1 million in cash and cash equivalents and $20.1 million availability under the New Revolving Facility. As of December 31, 2011, there were no borrowings outstanding under the New Revolving Facility, and there were $9.2 million of outstanding letters of credit issued against the New Revolving Facility.

Warrant Agreement

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

Each Warrant entitles its holder to purchase one share of common stock at an exercise price of $40.94 (the “Exercise Price”), subject to adjustment for, among other things, the matters described below. Except as otherwise set forth in the Warrant Agreement, Warrants may be exercised at any time after issuance until the Expiration Date. Holders that elect to exercise the Warrants must do so by (i) providing written notice of such election to the Warrant Agent prior to the Expiration Date, in the form prescribed in the Warrant Agreement, (ii) surrendering to the Warrant Agent the certificate evidencing such Warrants, and (iii) (x) paying the applicable exercise price for all Warrants being exercised or (y) if a change of control or similar transaction occurs where the Warrants would become exercisable for cash, in lieu of paying the Exercise Price, notify the Warrant Agent that such holder elects to receive a cash payment equal to the net amount payable in such transaction with respect to the number of shares such Warrants are being exercised for in excess of the Exercise Price for all such Warrants.

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

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

Contractual Obligations and Commercial Commitments

The following table provides a summary of our contractual obligations and commercial commitments as of December 31, 2011.  Other non-current liabilities included in our consolidated balance sheet that may not be fully disclosed below include accrued pension and post retirement costs.  Refer to Notes 15 and 16 of the Notes to the Consolidated Financial Statements.

61

	Total		Less Than 1 year		1-3 years		3-5 years		More than 5 years
	(In millions)
Long-term debt (including interest)	$	314.4	$	25.6	$	50.5	$	238.3	$	—
Leases:
Railcar leases	19.4		7.0		9.0		3.4		—
Terminal leases	1.1		0.3		0.6		0.2		—
Ports of Indiana wharfage	4.1		0.3		0.5		0.5		2.7
Property leases	6.5		0.6		1.3		1.0		3.7
Capital leases	0.4		0.4		—		—		—
Commodities
Coal contracts	17.1		17.1		—		—		—
Natural gas	1.7		1.7		—		—		—
Denaturant	1.0		1.0		—		—		—
Corn	7.8		7.8		—		—		—
Other:
Barge and Truck	3.5		3.5		—		—		—
IT services and licenses	0.5		0.4		0.1		—		—
Master Development Agreement (1)	1.9		1.7		0.3		—		—
Total Contractual obligations	$	379.4	$	67.4	$	62.3	$	243.4	$	6.4

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

Environmental Matters

We are subject to extensive federal, state and local environmental, health and safety laws, regulations and permit conditions (and interpretations thereof), including, among other things, those relating to the discharge of hazardous and other waste materials into the air, water and ground, the generation, storage, handling, use, transportation and/or disposal of hazardous materials, and the health and safety of our employees. 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.  We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties or other impacts of our operations.  We may be adversely affected by environmental, health, and safety laws, regulations, and liabilities.

For more information about our environmental compliance and actual and potential environmental liabilities, see “Business — Environmental and Regulatory Matters.’’

Market Risks

We are exposed to various market risks, including changes in commodity prices and changes in interest rates.

Commodity Price Risks

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

62

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 cost for the year ended December 31, 2011, was approximately 96.1% higher than for the year ended December 31, 2010.  Our weighted-average gross corn cost for the year ended December 31, 2010, was approximately 5.3% higher than for the year ended December 31, 2009.

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. Under these arrangements, we assume the risk of a decrease in the market price of corn between the time this price is fixed and the time the corn is delivered.  At December 31, 2011, we had firm-price purchase commitments to purchase approximately 1.2 million bushels of corn for delivery through February 2012.  We also had future contracts to sell 45 thousand bushels of corn.  At December 31, 2010, we had firm-price purchase commitments to purchase approximately 3.0 million bushels of corn for delivery through March 2011.  We have elected to account for these transactions as normal purchases under ASC 815, and accordingly, did not mark these transactions to market.

From time to time, we enter 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 ASC 815. These futures contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in “(Loss) gain on derivative transactions, net” on the condensed consolidated statements of operations. The fair value of these derivative contracts is recognized in other current assets in the condensed consolidated balance sheet, net of any cash received from the brokers. At December 31, 2011, we had 9 short March 2012 corn future contracts at an average price of $6.34 per bushel.  At December 31, 2010, we had 765 long March 2011 corn futures contracts at an average price of $6.01 per bushel.

We are also subject to market risk with respect to ethanol pricing. Our ethanol sales are priced using contracts that can either be based upon a fixed price 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, 2011, we had contracts to sell 3.9 million gallons of ethanol at fixed prices.  At December 31, 2010, we had fixed price contracts to sell 11.7 million gallons of ethanol.  These sale transactions would not be marked to market as they qualify for the normal sales exemption under ASC 815.

From time to time, we also sell forward ethanol using contracts where the price is determined at a point in the future based upon an ethanol index price plus or minus a fixed amount. At December 31, 2011, we had sold 58.1 million gallons of ethanol at index prices using Platts and OPIS indices. At December 31, 2010, we had sold 17.6 million gallons of ethanol at index prices using Platts and OPIS indices. When we have these arrangements, we assume the risk of a price decrease in the market price of ethanol.  These sale transactions would not be marked to market as they qualify for the normal sales exemption under ASC 815.

From time to time, we enter into ethanol futures contracts and ethanol swaps contracts in connection with the sale of ethanol. We account for these transactions under ASC 815. These futures contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in “(Loss) gain on derivative transactions, net” on the condensed consolidated statements of operations. The fair value of these derivative contracts is recognized in prepaid expenses and other current assets in the condensed consolidated balance sheet, net of any cash received from the brokers. At December 31, 2011, we were long 210 thousand gallons of Platts’ swaps.  For the Platts’ swaps, 3.1 million were

63

expired but still subject to settlement.  We did not have any futures contracts to sell ethanol at December 31, 2010.

We may also be subject to market risk with respect to our supply of natural gas which is consumed during the production of ethanol and its co-products and has historically been subject to volatile market conditions. Natural gas prices and availability are affected by weather conditions, overall economic conditions and foreign and domestic governmental regulation.  At December 31, 2011, we had purchased forward 527,000 MMBtu’s of natural gas at an average fixed price of $3.28 per MMBtu through January 2012.  At December 31, 2010, we had purchased forward 477,300 MMBtu’s of natural gas at an average fixed price of $4.30 per MMBtu through the first quarter of 2011. We have elected to account for these transactions as normal purchases under ASC 815 and, accordingly, have not marked these transactions to market.

We prepared a sensitivity analysis to estimate our exposure to market risk of our daily net commodity position. Our daily net commodity position consists of merchandisable agricultural commodity inventories, related purchase and sale contracts, and exchange-traded futures and exchange-traded and over-the-counter option contracts, including those contracts used to hedge portions of production requirements. The fair value of such daily net commodity position is a summation of the fair values calculated for each commodity by valuing each net position at quoted futures prices. Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10% adverse change in such prices. Based on the analysis performed, our highest position through the year ended December 31, 2011, had a fair value of $53.8 million, which would result in a $5.4 million market risk.  Our lowest position at December 31, 2011, had a fair value of $88.9 thousand, which would result in an $8.9 thousand market risk.  Our average position at December 31, 2011, was approximately $16.5 million, for an average market risk of $1.7 million.

Interest Rate Risk

The primary market risk associated with the Term Loan Agreement is sensitivity to changes in the interest rate. Borrowings under the Term Loan Agreement bear interest at (i) LIBOR (2% floor) plus 8.5% per annum or (ii) the alternate base rate plus 7.5% per annum.  The risk management strategies that we employ use various risk sensitivity metrics to measure such risks and to examine behavior under significant adverse market conditions. We performed a sensitivity analysis that measures the change in interest expense on our variable rate debt arising from a hypothetical 100 basis point adverse movement in interest rates. Based on our outstanding variable rate debt as of December 31, 2011, a hypothetical 100 basis point change in interest rates would not impact our interest expense because the adjusted LIBOR rate as of December 31, 2011, was 0.58% compared to our minimum Term Loan Facility adjusted LIBOR rate of 2.00% per annum according to the Term Loan Agreement.

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.

64

Impact of Recently Issued Accounting Standards

See Note 3, Summary of Significant Accounting Policies - Recent Accounting Pronouncements, of 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 year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010,and the year ended December 31, 2009	F-1
Consolidated Balance Sheets — December 31, 2011 and 2010	F-2
Consolidated Statements of Stockholders’ Equity (Deficit) — For the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009	F-3
Consolidated Statements of Cash Flows — For the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009	F-4
Notes to Consolidated Financial Statements	F-5
Report of Independent Registered Public Accounting Firm	F-54

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, John W. Castle, and Chief Financial Officer, Calvin Stewart, the Company carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report.  Based upon that evaluation, Mr. Castle and Mr. Stewart 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 include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed in such reports is accumulated and communicated to our management, including Mr. Castle and Mr. Stewart, 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.

65

Changes in Internal Control over Financial Reporting

Based upon the evaluation performed by our management, which was conducted with the participation of Mr. Castle and Mr. Stewart, there has been no change in our internal control over financial reporting during the fourth quarter of 2011 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 13a-15(f) or Rule 15d-15(f) under the Exchange Act.  Management, with the participation of Mr. Castle and Mr. Stewart, assessed the effectiveness of our internal control over financial reporting as of December 31, 2011.  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, 2011, our internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved.

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.

66

PART III

Item 10.  Directors and Executive Officers of the Registrant

The following table contains information regarding our current directors and executive officers.  Directors hold office until their terms expire and their successors have been elected and qualified.  Executive officers hold their positions until the annual meeting of the Board of Directors (the “Board”) or until their respective successors are elected and qualified.

Name	Age	Position
John W. Castle	47	Chief Executive Officer and Director
Calvin Stewart	44	Chief Financial Officer
Benjamin J. Borgen	37	Senior Vice President, Commodity Risk Management
Eugene I. Davis	56	Chairman of the Board of Directors
Timothy J. Bernlohr	52	Director and Chairman of the Compensation Committee
Kurt M. Cellar	42	Director and Chairman of the Audit Committee
Douglas Silverman	33	Director
Carney Hawks	37	Director

Executive Officers

John W. Castle. Mr. Castle was appointed Chief Executive Officer on November 22, 2011.  Mr. Castle has been a Director since August 2011.  Mr. Castle joined the Company in April 2010 as Chief Financial Officer. Before joining the Company, Mr. Castle served as Senior Vice President of Operations and Chief Financial Officer of White Energy, Inc., an ethanol production company, starting in November 2005. From August 2004 to November 2005, Mr. Castle was director of accounting for Dresser, Inc., a global manufacturer of highly engineered energy infrastructure and oilfield products and services. Mr. Castle has also served as Vice President and Chief Financial Officer at Rohn Industries, Inc. and as Vice President, Treasurer and Corporate Controller of Telxon Corporation. Previously, Mr. Castle was a member of Paxton Associates LLC, a provider of financial and operational assessment services. Mr. Castle has also held accounting and financial management positions at Mosler Inc. and Litton Industries, Inc. Mr. Castle is a Certified Public Accountant with a Masters of Business Administration from Xavier University and a Bachelor of Science in Accounting from Eastern Illinois University.

Calvin Stewart. Mr. Stewart was appointed Chief Financial Officer on November 22, 2011.  Mr. Stewart joined the Company in November 2010 as Chief Accounting and Compliance Officer. Prior to joining the Company, Mr. Stewart served most recently as Chief Financial Officer of White Energy, Inc., an ethanol production company. Mr. Stewart joined White Energy in June 2006 as Corporate Controller. From August 2004 to June 2006, Mr. Stewart served as Manager, Technical Accounting and Sr. Manager, Corporate Accounting, at Dresser, Inc., a global manufacturer of highly engineered energy infrastructure and oilfield products and services. Previously, Mr. Stewart was Manager, Accounting and Finance, at Siemens Maintenance Services. Mr. Stewart also served as Plant Operations Controller and Director of Accounting and Finance for Morningstar Foods, a national leader in dairy food and beverage manufacturing and distribution. Mr. Stewart is a Certified Public Accountant with a Masters of Business Administration from Southern Methodist University’s Edwin L. Cox School of Business and a Bachelor of Science in Finance, cum laude, from Towson University.

Benjamin J. Borgen. Mr. Borgen became our Senior Vice President, Commodity Risk Management in March 2010. From June 2009 to February 2010, Mr. Borgen managed ethanol trading as Director of Commodity Trading for Barclays Capital. From April 2008 to May 2009, Mr. Borgen served as Director of Ethanol Trading at Saracen Energy Partners. Mr. Borgen served as Vice President of Ethanol Trading and Marketing for Sempra Energy Trading, from March 2005 to March 2008. Mr. Borgen was also a Senior

67

Energy Trader with PG&E National Energy Group. In these positions, Mr. Borgen was responsible for strategy development and evaluation, asset evaluation, and management of commodity positions. Mr. Borgen holds a Bachelor of Arts degree from Concordia College in Moorhead, Minnesota.

Directors

Eugene I. Davis. Mr. Davis became Chairman of the Board in March 2010. Mr. Davis is currently Chairman and Chief Executive Officer of PIRINATE Consulting Group, LLC (‘‘PIRINATE’’), a privately held consulting firm specializing in turnaround management, merger and acquisition consulting and hostile and friendly takeovers, proxy contests and strategic planning advisory services for domestic and international public and private business entities. Since forming PIRINATE in 1997, Mr. Davis has advised, managed, sold, liquidated and served as a Chief Executive Officer, Chief Restructuring Officer, Director, Committee Chairman and Chairman of the Board of a number of businesses operating in diverse sectors such as telecommunications, automotive, manufacturing, high-technology, medical technologies, metals, energy, financial services, consumer products and services, import-export, mining and transportation and logistics. Previously, Mr. Davis served as President, Vice Chairman and Director of Emerson Radio Corporation and Chief Executive Officer and Vice Chairman of Sport Supply Group, Inc. He began his career as an attorney and international negotiator with Exxon Corporation and Standard Oil Company (Indiana) and as a partner in two Texas-based law firms, where he specialized in corporate/securities law, international transactions and restructuring advisory. Mr. Davis graduated with a B.A. degree in International Politics from Columbia University and graduated with a Masters in International Affairs degree in International Law and Organization from the School of International Affairs of Columbia University and a J.D. from Columbia University School of Law.  Mr. Davis is also a director of Atlas Air Worldwide Holdings, Inc., DEX One Corp., Global Power Equipment Group Inc., GSI Group, Inc., Spectrum Brands, Inc., and U.S. Concrete, Inc.  He is also a director of Trump Entertainment Resorts, Inc. and Lumenis Ltd., whose common stock is registered under the Securities Exchange Act of 1934 but does not publicly trade. Mr. Davis is also on the board of Ambassadors International.  On May 25, 2011, Ambassadors International sold substantially all of its assets through a Chapter 11 bankruptcy process and is winding up its activities, after which Ambassadors will no longer be a publicly traded company. During the past five years, Mr. Davis has also been a director of American Commercial Lines Inc., Delta Airlines, Foamex International Inc., Footstar, Inc., Granite Broadcasting Corporation, Ion Media Networks, Inc., Knology, Inc., Media General, Inc., Mosaid Technologies, Inc., Ogelbay Norton Company, Orchid Cellmark, Inc., PRG-Schultz International Inc., Roomstore, Inc., Rural/Metro Corp., SeraCare Life Sciences, Inc , Silicon Graphics International, Smurfit-Stone Container Corporation, Solutia Inc., Spansion, Inc., Tipperary Corporation, Viskase, Inc. and YRC Worldwide, Inc. Our Board has determined that Mr. Davis should serve as a director and as Chairman of the Board based on his extensive experience as a chairman and director of emerging companies as well as his management and legal expertise.

Timothy J. Bernlohr.  Mr. Bernlohr has been a Director since March 2010.  Mr. Bernlohr is the founder, and since 2004 managing member of TJB Management Consulting, LLC which specializes in providing project specific services to businesses in transformation, including restructurings, interim executive management, and strategic planning services. From April 1997 until July 2005 Mr. Bernlohr held positions of increasing authority with RBX Industries, Inc. (“RBX”), including serving as its President and Chief Executive Officer.  RBX was a nationally recognized leader in the design, manufacture, and marketing of rubber and plastic materials to the automotive, construction, and industrial markets.  RBX was sold to multiple buyers in 2004 and 2005.  Prior to joining RBX in 1997, Mr. Bernlohr spent 16 years in the international and industry products divisions of Armstrong World Industries where he served in a variety of management positions.  Mr. Bernlohr presently serves as Chairman of the boards of Champion Home Builders, Inc. and The Manischewitz Company and as Lead Director of Chemtura Corporation.  Mr. Bernlohr also serves as a director of Rock Tenn Company, Atlas Air Worldwide Holdings, Aveos Fleet Performance, Inc., US Power Generation, Inc. Bally Total Fitness Corporation, Inner City Media Corporation, and Neenah Foundry Enterprises, Inc.  Within the past 5 years Mr. Bernlohr has served as a director of Hayes Lemmerz International, Hilite International, Cadence Innovation, BHM Technologies, Ambassadors International, Nybron Flooring International, Smurfit Stone Container Corporation, General Insulation Company, PetroRig Pte, Ltd., WCI Steel Corporation, Trident Resources Corporation, Zemex Materials, and General Chemical Industrial Products.  Mr. Bernlohr is a 1981 graduate of The Pennsylvania State University.  Our Board has determined Mr. Bernlohr should serve as a director based upon his extensive executive experience and his ongoing and prior board service on both private and public companies.

68

Kurt M. Cellar. Mr. Cellar has been a Director since March 2010. Mr. Cellar has been a self-employed consultant and board member since January 2008. From January 2007 through January 2008, Mr. Cellar was a partner and Portfolio Manager at Bay Harbour Management, L.C. (‘‘Bay Harbour’’). Prior to Bay Harbour, he was an associate at Remy Investors and Consultants, Inc. (‘‘Remy’’), where he sourced and analyzed public and private investment opportunities. Prior to Remy, Mr. Cellar was an associate at LEK/Alcar Consulting Group, Inc., a strategic management consulting firm. Mr. Cellar received a B.A. degree in Economics and Business from the University of California, Los Angeles and his M.B.A. in Finance and Entrepreneurial Management from the Wharton School at the University of Pennsylvania. Mr. Cellar currently serves on the board and is audit committee chairman of Six Flags Entertainment and currently serves on the board and is an audit committee member of Hawaiian Telcom. Our Board has determined that Mr. Cellar should serve as a director based on his extensive financial, accounting, and investing experience and his prior and ongoing board service for other public companies.

Douglas Silverman. Mr. Silverman has been a Director since March 2010. Mr. Silverman founded Senator Investment Group LP (“Senator”) and is responsible for portfolio management and all operations of a 24 employee partnership which manages approximately $3.5 billion of assets. Prior to co-founding Senator, Mr. Silverman spent nearly six years at York Capital Management (“York”) where he was a Managing Director and Co-Portfolio Manager or York Global Value Partners, a hedge fund focused on value and event investing in equity and credit opportunities.  Prior to joining York, Mr. Silverman was an investment banker in the Leveraged Finance department at Merrill, Lynch & Co.  Mr. Silverman received a B.A. in Economics, cum laude, from Princeton University. Our Board has determined that Mr. Silverman should serve as a director based on his extensive financial, accounting, and investing experience.

Carney Hawks. Mr. Hawks has been a Director since March 2010. Mr. Hawks is an original partner with Brigade, a credit-focused, asset management firm founded in 2007. Prior to joining Brigade, he was a Managing Director in the High Yield Division of MacKay Shields (“MacKay”) from 1998 through 2006.  Mr. Hawks is a graduate (with Distinction) of the University of Virginia’s McIntire School of Commerce and a CFA Charterholder.  Our Board has determined that Mr. Hawks should serve as a director based on his extensive financial and investing experience.

Board Composition

Under our third amended and restated certificate of incorporation and amended and restated bylaws, the number of directors at any one time is set by resolution of the Board. Currently, the Board consists of six members, of which three have affirmatively been determined to be independent. Upon emergence from bankruptcy and appointment of our new Board, the Board affirmatively determined that Messrs. Davis, Bernlohr and Cellar are independent of the Company and our management under the NASDAQ Stock Market Rules and Rule 10A-3 of the Exchange Act. In addition, although the Board has not made a formal determination on the matter, we believe that Messrs. Hawks and Silverman may not be independent of the Company and our management under the NASDAQ Stock Market Rules. In making this independence determination, we noted in particular the following: (i) Mr. Hawks is an original partner with Brigade, (ii) Mr. Silverman is a Managing Partner and Co-Chief Investment Officer with Senator, (iii) Brigade received approximately 27% in aggregate principal amount of Notes and shares of common stock sold in a private placement that closed on March 15, 2010, (iv) Senator received approximately 12% in aggregate principal amount of Notes and shares of common stock sold in a private placement that closed on March 15, 2010, (v) Senator and Brigade received an aggregate of $500,000 as a commitment fee as consideration for their commitment to backstop our August 2010 Notes offering and (vi) Senator and Brigade are lenders under the Term Loan Agreement.

We note that The NASDAQ Stock Market LLC does not view ownership of even a significant amount of stock, by itself, as a bar to an independence finding. Although it is unclear under NASDAQ Stock Market Rules whether Messrs. Hawks and Silverman would be considered independent, we do not

69

believe that any of the above factors would cause either of Messrs. Hawks or Silverman to have a relationship with us that would impair their independence for the purposes of NASDAQ Stock Market Rule 5605(a)(2).

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

Stockholders desiring to communicate with the Board may do so by mail addressed as follows: Board of Directors, Aventine Renewable Energy Holdings, Inc., One Lincoln Centre, 5400 LBJ Freeway, Suite 450, Dallas, TX 75240. We believe our responsiveness to stockholder communications to the Board has been excellent.

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

Board Committees and Director Nominations

In March 2010, we reconstituted our Board pursuant to our Plan. In accordance with our Plan, Messrs. Davis, Cellar, Silverman and Hawks were appointed to the Board by Brigade, Nomura Corporate Research & Asset Management, Inc., Whitebox, Senator and SEACOR Capital Corporation, which constituted a group that formerly held (or managed affiliated funds or accounts that formerly held) the Old Notes that were cancelled pursuant to our Plan. Mr. Manuel, as our former Chief Executive Officer, was also appointed to our Board pursuant to our Plan, but he subsequently retired from the Board on August 19, 2011 concurrent with his retirement as Chief Executive Officer.  On March 15, 2010, our Board voted to increase the size of the Board by one, and Mr. Bernlohr was selected to fill the resulting vacancy. We consequently reconstituted our Audit Committee and Compensation Committee. On August 19, 2011, the Board voted to appoint Mr. Castle to fill the vacancy created by Mr. Manuel’s departure.  The Board will also establish such other committees as it deems appropriate, in accordance with applicable law and regulations and our third amended and restated certificate of incorporation and amended and restated bylaws.

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

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

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

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

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

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

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

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

Our Board has adopted a written charter for the Audit Committee, which is available on our website.

70

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

Our Board has adopted a written charter for the Compensation Committee, which is available on our website at www.aventinerei.com.

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

Board Leadership Structure

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

Board Risk Assessment and Control

Our risk management program is overseen by our Board and its committees, with support from our management. Our Board oversees an enterprise-wide approach to ethanol industry risk management, designed to support the achievement of organizational objectives, including strategic objectives, to improve long-term organizational performance and enhance stockholder value. A fundamental part of risk management is a thorough understanding of the risks a company faces, understanding of the level of risk appropriate for the Company and the steps needed to manage those risks effectively. As an example, we may manage commodity price risk by, when appropriate, entering into appropriate hedge agreements with approved counterparties. Our Board takes an active role in determining the types and levels of hedging activity pursued. Together with management’s recommendations, our Board may approve the

71

counterparties with whom we enter into hedge agreements and the commodity levels hedged. The involvement of the full Board in setting our business strategy is a key part of its overall responsibilities and together with management determines what constitutes an appropriate level of risk for us.

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

Compensation Committee Interlocks and Insider Participation

For the fiscal year ended 2011, none of our then executive officers served as a member of the board of directors or Compensation Committee of any entity that had one or more of its executive officers serving as a member of our Board or Compensation Committee.

Corporate Governance

The charters of the Compensation Committee and Audit Committee, as well as our Corporate Governance Guidelines and our Code of Business Conduct and Ethics that applies to our directors, officers and employees (including our Chief Executive Officer, Chief Financial Officer, principal accounting officer, controller or other persons performing similar functions), are available on our website (www.aventinerei.com) or in print upon written request at no charge.  If we amend or grant any waivers under the codes that are applicable to our Chief Executive Officer, our Chief Financial Officer, or our principal accounting officer and that relate to any element of the SEC’s definition of a code of ethics, which we do not anticipate doing, we will promptly post that amendment or waiver on our website, www.aventinerei.com, under “Investor Relations”.

Item 11.  Executive Compensation

Compensation Overview

Introduction

This discussion (1) provides an overview of our compensation policies and programs; (2) generally explains our compensation objectives, policies and practices with respect to our executive officers; and (3) identifies the elements of compensation for each of the individuals identified in the following table, whom we refer to as our named executive officers (each a ‘‘NEO’’ and collectively, “NEOs”).

Name	Position
John W. Castle	Chief Executive Officer and Director
Thomas L. Manuel	Former Chief Executive Officer and Director
Calvin Stewart	Chief Financial Officer
Benjamin Borgen	Senior Vice President, Commodity Risk Management

Compensation Program Objectives

The Company believes that every decision relating to executive compensation should be made with the aim to enhance stockholder value.  We believe that this overall goal can be achieved by balancing three objectives:

72

·To attract and retain the talent needed by the Company to create value;

·To reward, and thereby motivate, that talent for sustainable value creation; and

·To meet the Company’s attraction and alignment objectives at the lowest reasonable cost to the stockholders.

Compensation Elements

The Company’s compensation program consists of four main elements:

·Base salary;

·Annual cash bonuses;

·Equity-based awards; and

·Company-wide benefits.

Base Salary. Base salaries represent the guaranteed portion of total compensation designed to attract and retain managers.

Annual Bonuses.  The Company provides a cash bonus opportunity as part of the total expected compensation used to attract and retain its management, as well as a component of rewarding, and thereby encouraging, value creation.

For 2011, the Board approved a bonus plan that provides for awards to senior management based upon achievement of corporate objectives (corporate pool) or commodity risk objectives.  All of the NEOs had half or all of their bonuses funded via the corporate pool of CRM as follows:

Executive	Corporate Pool		CRM Pool
John W. Castle	100	%	—
Thomas L. Manuel	100	%	—
Calvin Stewart	100	%	—
Benjamin J. Borgen	50	%	50	%

Corporate objectives included ramping up of ethanol production across the Company’s plants while controlling production, distribution, and other costs.  The board gauged the degree to which objectives were met using pre-determined guidelines, but ultimately used its judgment in awarding bonuses to managers.

Equity-Based Awards. The Company grants equity-based compensation as part of the overall expected value of pay used to attract and retain its senior management, as well as a tool for directly aligning the interests of senior managers and the stockholders.  In 2011 certain NEOs were awarded hybrid equity units by the Company.  The assumptions and methodology used to determine such amounts are set forth in Note 19 of Notes to Consolidated Financial Statements.

Company-wide Benefits.  Senior management does not get any other form of cash or equity compensation or perquisites besides those mentioned in the foregoing description.  Senior management participates in the Company health and retirement programs on the same terms as other employees, whereby contributions made under the plan include a match, at the Company’s discretion, of an employee’s contribution to the plan.

73

Summary Compensation Table

The following table sets forth the total compensation for certain of the Company’s current and former named executive officers for the years ended December 31, 2011 and 2010, as applicable:

Name and Principal Position	Year	Salary ($)		Bonus ($)(1)	Stock Awards ($)(2)	Option and Hybrid Equity Units ($)(2)	Non-Equity Incentive Plan Compensation ($)	Nonqualified Deferred Compensation Earnings	All Other Compensation ($)(4)	Total
(a)	(b)	(c)		(d)	(e)	(f)	(g)	(h)	(i)	(j)
John W. Castle,	2011	392,923		268,000	—	805,275	—	—	15,317	1,481,515
CEO, CFO	2010	262,500		420,000	875,000	2,191,750	—	—	—	3,749,250
Thomas L. Manuel,	2011	317,308	(3)	—	—	1,380,981	—	—	1,983,588	3,681,877
Former CEO	2010	403,846	(3)	750,000	4,264,911	2,027,889	—	—	89,355	7,536,001
Calvin Stewart CFO	2011	255,769		100,000	—	276,200	—	—	15,088	647,057
Benjamin Borgen,	2011	400,000		—	—	785,626	—	—	15,271	1,200,897
Sr. VP	2010	323,077		589,000	2,522,495	709,838	—	—	10,154	4,154,564

(1)  Bonuses paid to our NEOs were paid at the discretion of the Board for performance during 2011.  No NEO earned non-equity incentive plan compensation for 2011 and thus, no amounts were reported in column (g).

(2)   The value shown under “Stock Awards” and “Option and Hybrid Equity Units” in the table above represents the aggregate grant date fair value computed in accordance with ASC Topic 718, Compensation—Stock Compensation (“ASC 718”).  The assumptions and methodology used to determine such amounts are set forth in Note 19 of Notes to Consolidated Financial Statements.

(3)Mr. Manuel began employment on March 15, 2010, as the Company’s Chief Executive Officer.  He retired on August 19, 2011.  As part of the Mutual Release Agreement, the Executive became fully vested in all hybrid equity units granted in 2011.  The terms of the hybrid equity awards were modified so as to be measured as of August 19, 2012 instead of December 31, 2014, although no additional compensation expense will be recognized as a result of the modification.  The amounts provided under column (f) for Mr. Manuel include the grant date value of the hybrid equity units granted to Mr. Manuel.  The fair value on the modification date of the modified hybrid equity units was $1.06 per unit, based on assumptions set forth in Note 19 of Notes to Consolidated Financial Statements.

(4)   All Other Compensation consisted of:

Executive	Year	401(k) Company Matching	Separation Pay	Benefits	Acceleration and Vesting of Stock Awards	2011 Total
John W. Castle	2011	14,700	—	617	—	15,317
Thomas L. Manuel (1)	2011	—	1,040,000	3,088	940,500	1,983,588
Calvin Stewart	2011	14,471	—	617	—	15,088
Benjamin Borgen	2011	14,654	—	617	—	15,271

(1)This row consists substantially of termination compensation paid during 2011 to Mr. Manuel pursuant to his Mutual Release Agreement effective on August 19, 2011.  The termination compensation received was:

·      a lump sum separation payment in the amount of $1,040,000,

74

·      medical and dental coverage through February 2013 for a cost of approximately $12,000, of which $2,667 was paid in 2011, and

·      accelerated vesting of Mr. Manuel’s outstanding unvested equity awards, which we valued at $940,500.

Summary of Employment Agreements with NEOs

On August 19, 2011, the Company announced the retirement of Thomas Manuel as Chief Executive Officer, and the appointment of John Castle as Interim Chief Executive Officer and Calvin Stewart as the Interim Chief Financial Officer.  On November 22, 2011, the Company announced the appointment of John Castle as President and Chief Executive Officer and a member of the Board of Directors.  The Company also announced the appointment of Calvin Stewart as Chief Financial Officer.  The Company has agreements with all three of the current NEOs, later referred to as the “NEO Employment Agreements.”  Those agreements are summarized as follows:

Employment Agreements

John W. Castle. On November 21, 2011, the Company and Mr. Castle entered into an employment agreement (the ‘‘Castle Employment Agreement’’) with a term beginning on November 1, 2011, and expiring on December 31, 2014. The terms of the Castle Employment Agreement provide for, among other things, (i) a base annual salary of $500,000, (ii) an annual bonus with a target of at least 100% of Mr. Castle’s base salary and an opportunity to earn an incentive bonus of up to another 100% of his base salary each year, in each case based on attainment of performance metrics as determined by the Board of Directors or its Compensation Committee.

In addition, pursuant to the Castle Employment Agreement, Mr. Castle was awarded options to purchase 100,000 shares of common stock of the Company with an exercise price equal to the per share fair market value of the common stock on May 5, 2010, of $43.75, as determined by the Board, and 25,000 shares of Restricted Stock. 50% of the options and 50% of the Restricted Stock will vest in three equal installments on each of the first two anniversaries of May 5, 2010, and December 31, 2012, subject to Mr. Castle’s continuing employment with the Company. 50% of the options and 50% of the Restricted Stock will vest subject to the attainment of reasonable performance criteria determined by the Board, which were achieved for fiscal year 2010. The options will expire on the 10 year anniversary of May 5, 2010.

Calvin Stewart.  . On November 22, 2011, the Company and Mr. Stewart entered into an employment agreement (the ‘‘Stewart Employment Agreement’’) with a term beginning on November 22, 2011, and expiring on December 31, 2014. The terms of the Stewart Employment Agreement provide for, among other things, (i) a base annual salary of $300,000, (ii) an annual bonus with a target of at least 100% of Mr. Stewart’s base salary and an opportunity to earn an incentive bonus of up to another 100% of his base salary each year, in each case based on attainment of performance metrics as determined by the Board of Directors or its Compensation Committee.

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

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

75

substantially the same terms as Mr. Castle. Additionally, in October 2010, the Board approved the grant of 40,000 restricted stock units to Mr. Borgen.

Manuel Mutual Release Agreement.  Pursuant to Mr. Manuel’s Mutual Release Agreement between him and the Company, Mr. Manuel was entitled to receive (a) a lump sum separation payment of $1,040,000, (b) continued payment of Mr. Manuel’s group term life insurance premiums under the Company’s (or equivalent) plans for eighteen months, (c) reimbursement from the Company for COBRA continuation coverage premiums to the extent elected, and (d) accelerated vesting of all outstanding equity awards.  In addition, the withholding obligation for the restricted stock units schedule to vest were settled in shares, and Mr. Manuel’s options are now entitled to be exercised at any time through August 19, 2012.

Summary of Equity Plans

2010 Equity Incentive Plan

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

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

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

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

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

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

The Board or a committee of the Board will determine the terms of any awards granted under the 2010 Equity Incentive Plan, including, without limitation, the number of shares subject to an award, vesting criteria, performance conditions, the manner of exercise, and the effect of certain corporate transactions. Unless otherwise provided in an award agreement, awards granted under the plan generally vest, or the restrictions applicable to the awards generally lapse, on the third anniversary of the date of grant. In the event of a ‘‘Change in Control’’ (as defined in the plan), the Board or committee may provide for the acceleration of the vesting, lapse of restrictions, or performance periods with respect to all or any portion of outstanding awards. With respect to awards of stock options, unless otherwise provided in an award agreement, unvested options expire upon termination of employment or service of the participant for any reason, and the vested options remain exercisable for (i) one year following termination of employment or service by reason of a participant’s death or disability, but not later than the expiration of the term of the options or (ii) 90 days following termination of employment or service for any reason other than the participant’s death or disability, and termination for ‘‘Cause’’ (as defined in the plan), but not later than the

76

expiration of the term of the options, and (iii) both unvested and vested options expire upon the termination of the participant’s employment or service by the Company for Cause.

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

In 2011, certain of the NEOs were awarded hybrid equity units by the Company as follows:

Executive	Grant Date	Hybrid Equity Units	Threshold Price per Share
Thomas L. Manuel	4/16/2011	78,154	$	19.60
John W. Castle	4/16/2011	45,573	$	19.60
Calvin Stewart	4/16/2011	15,631	$	19.60
Benjamin J. Borgen	4/16/2011	44,461	$	19.60

Each unit granted for this year will translate into up to one share, depending on the average closing share price for the last 15 trading days of 2014, denoted as “S” in the following formula:

# Shares = # Units x (1 — 19.6/S)

For example, if a manager is granted 10,000 units, and S equals $40, then the manager would receive 5,100 shares (i.e., 10,000 units x (1 — 19.6/40) = 5,100).  If the stock price ends up higher, then the participant would receive more shares; if the stock price were lower, he or she would receive fewer shares.  If the stock price falls below $19.60, the participant would be granted no shares.

Thomas L. Manuel retired in August 2011.  As part of Mr. Manuel’s Mutual release Agreement, the vesting terms of the hybrid equity units were accelerated and vested on the termination date.  We modified the hybrid equity units by changing the measurement date.  The hybrid equity units will now be measured at the average closing share price for the last 15 trading days ending August 19, 2012.  This modification did not result in additional compensation expense for the Company.

77

Outstanding Equity Awards at Fiscal Year End

The following tables set forth the option, stock and hybrid equity unit awards outstanding for Aventine’s NEOs as of December 31, 2011:

		Option Awards
Name		Number of Securities Underlying Unexercised Options Exercisable (#)	Number of Securities Underlying Unexercised Option Unexercisable (#)	Option Exercise Price ($)		Option Expiration Date
John W. Castle	(1)	—	33,333	$	43.75	5/5/2020
	(2)(3)	66,667	—	$	43.75	5/5/2020
Calvin Stewart		—	—	—		—
Benjamin J. Borgen	(4)	—	17,100	$	45.60	3/15/2020
	(5)(6)	34,200	—	$	45.60	3/15/2020
Thomas L. Manuel		128,250	—	$	45.60	8/19/2012

		Stock Awards
Name		Number of Restricted Stock Units That Have Not Vested (#)		Market Value of Restricted Stock Units That Have Not Vested ($)		Number of Restricted Shares That Have Not Vested (#)		Market Value of Restricted Shares That Have Not Vested ($)
John W. Castle	(1)	—		—		8,333	(2)	$	49,165
	(2)(3)	—		—		—		—
Calvin Stewart		—		—		—		—
Benjamin J. Borgen	(4)	13,334	(4)	$	78,671	18,525	(5)	$	109,298
	(5)(6)	—		—		—		—
Thomas L. Manuel		—		—		—		—

		Hybrid Equity Awards (HEA) Number of HEA that have vested (#)	Hybrid Equity Awards (HEA) Number of HEA that have not vested (#)	Threshold Price ($)		Unit measurement Date
John W. Castle	(3)	22,787	22,786	$	19.60	12/31/2014
Calvin Stewart	(8)	7,816	7,815	$	19.60	12/31/2014
Benjamin J. Borgen	(7)	22,231	22,230	$	19.60	12/31/2014
Thomas L. Manuel		78,154	—	—		8/19/2012

(1)  These stock options have ten-year terms. The vesting schedules for Mr. Castle’s unvested awards are outlined below:

78

Name	# of Options	Vesting Schedule
Castle	16,667	5/5/2012
Castle	16,666	12/31/2012

(2)The vesting schedules for Mr. Castle’s unvested restricted stock are outlined below:

Name	# of Restricted Shares	Vesting Schedule
Castle	4,167	5/5/2012
Castle	4,166	12/31/2012

(3)The vesting schedule for Mr. Castle’s Hybrid Equity Awards is outlined below:

Name	# of Hybrid Equity Awards s	Vesting Schedule
Castle	22,786	12/31/2014

(4)These stock options have ten-year terms. The vesting schedules for Mr. Borgen’s unvested awards are outlined below:

Name	# of Options	Vesting Schedule
Borgen	8,550	3/15/2012
Borgen	8,550	12/31/2012

(5)The vesting schedule for Mr. Borgen’s unvested restricted stock units is outlined below:

Name	# of Restricted Stock Units	Vesting Schedule
Borgen	13,334	10/13/2012

(6)The vesting schedules for Mr. Borgen’s unvested restricted stock are outlined below:

Name	# of Restricted Shares	Vesting Schedule
Borgen	9,263	3/15/2012
Borgen	9,262	12/31/2012

(7)The vesting schedule for Mr. Borgen’s Hybrid Equity Awards is outlined below:

Name	# of Hybrid Equity Awards s	Vesting Schedule
Borgen	22,230	12/31/2014

(8)The vesting schedule for Mr. Stewart’s Hybrid Equity Awards is outlined below:

Name	# of Hybrid Equity Awards s	Vesting Schedule
Stewart	7,815	12/31/2014

79

Retirement Plans; Non-Qualified Deferred Compensation Plans

Other than its 401(k) plan, the Company currently does not maintain any retirement or non-qualified deferred compensation plans for any of its NEOs that provide for the payment of retirement benefits or benefits that will be paid primarily following retirement.  The Company has a 401(k) plan covering substantially all of its employees. Contributions made under the defined contribution plans include a match, at the Company’s discretion, of an employee’s contribution to the plans.

Termination and Change of Control Benefits

Termination Benefits

The NEO Employment Agreements provide for certain severance benefits upon a termination without “Cause” or for “Good Reason,” which are contingent upon a NEO executing and delivering a general release and waiver of claims in favor of the Company.

The NEO Employment Agreements generally define Cause as:

·willful misconduct or gross negligence of a material nature in the performance of the NEO’s duties;

·being convicted of, or pleading guilty or nolo contendere to a felony (other than a traffic violation);

·willful theft or embezzlement from the Company or our affiliates; or

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

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

·a material diminution in authority, duties or responsibilities;

·a material diminution in base salary;

·a relocation of the NEO’s principal business location to a location outside of Dallas, Texas; or

·any material breach of the NEO Employment Agreement by the Company.

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

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

80

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

Change of Control Benefits

The options, Restricted Stock and Restricted Stock Units awarded to each NEO pursuant to their NEO Employment Agreements will vest immediately in the event of a “Change of Control.”  In addition, if (i) any payment or benefit a NEO receives in connection with a Change of Control is subject to the 20% excise tax under Section 4999 of the Internal Revenue Code and (ii) the sum of such payments and benefits exceeds 110% of the excise tax threshold, the NEO will be entitled to a gross up payment such the excise tax such that he will be in the same after tax position as if no will be reduced so as not to trigger excise tax under Section 4999 of such Code.  If (i) any payment or benefit a NEO receives in connection with a Change of Control is subject to the 20% excise tax under Section 4999 of the Internal Revenue Code and (ii) the sum of such payments and benefits does not exceed 110% of the excise tax threshold, the NEO entitlement to the payment and benefits will be reduced in the manner specified in the NEO Employment Agreement, to the level below which no excise tax will be imposed.

For purposes of the NEO Employment Agreements, a Change of Control means the occurrence of any of the following events:

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

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

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

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

Director Compensation

Our compensation program for non-employee directors consists of:

Cash Compensation

·$50,000 annual cash retainer, payable in equal quarterly installments;

·Additional $25,000 annual retainer to the Chairman of the Board;

·Additional committee chair retainers of $10,000 per year for the Chair of the Audit Committee and $5,000 for other Committee Chairs;

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

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

81

Equity Compensation

·Annual grants totaling $35,000 in restricted stock units.  The Chairman of the Board of Directors receives an additional $40,000 in restricted stock units.  These awards vested as of December 31, 2011.

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

The following table sets forth certain information regarding the compensation earned by or awarded to each non-employee director who served on the Board in 2011:

Name	Fees Earned or Paid in Cash		Stock Awards		Total Compensation
John Castle	—		—		—
Eugene Davis	$	96,750	$	75,000	$	171,750
Kurt Cellar	$	81,750	$	35,000	$	116,750
Timothy Bernlohr	$	81,750	$	35,000	$	116,750
Carney Hawks (1)	$	69,500	$	35,000	$	104,500
Doug Silverman (2)	$	66,500	$	35,000	$	101,500

(1)Cash fees paid to Mr. Hawks are paid directly to Brigade.

(2)Cash fees paid to Mr. Silverman are paid directly to Senator.

(3)Represents the dollar amount recognized for financial statement reporting purposes in accordance with ASC 718 with respect to fiscal 2011 for restricted stock units awards, disregarding estimated forfeitures related to service-based vesting conditions.

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

The following table presents certain information with respect to the beneficial ownership of our shares by (a) any person or group known to us who beneficially owns more than five percent of our common stock, (b) each of our directors and NEOs and (c) all directors and executive officers as a group. The percentage of beneficial ownership is based on 8,392,341 shares outstanding at February 10, 2012. Except as otherwise noted in the footnotes below, because our stockholders are not subject to Section 13 or Section 16 of the Exchange Act and a substantial portion of our shares are held through the facilities of The Depository Trust Company, the table below has been prepared based upon the information furnished to us by our stockholders as of January 2012, and, in some cases, February 2012. The stockholders identified below may have acquired shares or sold, transferred or otherwise disposed of some or all of their shares since the date on which the information in the following table is presented.

Except as indicated in footnotes to this table, we believe that the stockholders named in this table have sole voting and investment power with respect to all shares of common stock shown to be beneficially owned by them, based on information provided to us by such stockholders.

82

Beneficial holders	Number of shares beneficially held	Percentage of beneficial ownership
5% of Stockholders:
Funds managed by Brigade Capital Management, LLC (1)	2,029,277	24.2	%
Funds managed by DW Investment Management LLP (2)	1,366,221	16.3	%
Senator Global Opportunity Master Fund L.P. (3)	1,152,455	13.7	%
Funds managed by Davidson Kempner Capital Management LLC (4)	778,713	9.3	%
Goldman Sachs Group, Inc. (5)	443,557	5.2	%
Directors and Named Executive Officers:
John W. Castle (6), (7)	108,334	1.3	%
Calvin Stewart (6)	—	—
Benjamin J. Borgen (6), (8)	133,542	1.6	%
Eugene I. Davis (6), (9)	1,645	*
Timothy J. Bernlohr (6)(9)	768	*
Kurt M. Cellar (6)(9)	768	*
Douglas Silverman (6), (9), (10)	768	*
Carney Hawks, excludes Brigade Capital Management, LLC (6)	768	*
All directors and executive officers as a group (8 persons)	246,593	2.9	%

* Denotes less than 1% beneficially owned.

(1) Stockholder’s address is 399 Park Avenue, 16th Floor, New York, New York 10022. Brigade Leveraged Capital Structures Fund Ltd. owns 1,873,386 shares, SEI Global Master Fund plc owns 18,599 shares, SEI Institutional Investments Trust owns 66,719 shares and SEI Institutional Managed Trust owns 70,573 shares. Donald E. Morgan III, as managing member of Brigade Capital Management, LLC, exercises voting and/or investment control with respect to the shares of the named entities.

(2) Stockholder’s address is 590 Madison Avenue, 9th Floor, New York, New York 10022.

(3) Stockholder’s address is 510 Madison Avenue, 28th Floor, New York, New York 10019. Alexander Klabin and Douglas Silverman, as co-managing members of the investment manager, exercise voting and/or investment control with respect to shares of Senator Global Opportunity Master Fund L.P.

(4) Stockholder’s address is 65 East 55th Street, 19th Floor, New York, New York 10022. Davidson Kempner Distressed Opportunities Fund LP owns 198,373 shares. Thomas L. Kempner, Jr. as executive managing member of DK Group LLC, Stephen M. Dowicz, as managing member of DK Group LLC, Scott E. Davidson, as deputy executive managing member of DK Group LLC, Timothy I. Levart, as managing member and chief operating officer of DK Group LLC, Robert J. Brivio, Jr., as managing member of DK Group LLC, Eric P. Epstein, as managing member of DK Group LLC, Anthony A. Yoseloff, as managing member of DK Group LLC, Avram Z. Friedman, as managing member of DK Group LLC, and Conor Bastable, as managing member of DK Group LLC, exercise voting and/or investment control with respect to the shares of Davidson Kempner Distressed Opportunities Fund LP. Davidson Kempner Distressed Opportunities International owns 344,476 shares. Thomas L. Kempner, Jr. as partner of DK Management Partners LP, Stephen M. Dowicz, as partner of DK Management Partners LP, Scott E. Davidson, as partner of DK Management Partners LP, Timothy I. Levart, as partner and chief operating officer of DK Management Partners LP, Robert J. Brivio, Jr., as partner of DK Management Partners LP, Eric P. Epstein, as partner of DK Management Partners LP, Anthony A. Yoseloff, as partner of DK Management Partners LP, Avram Z. Friedman, as partner of DK Management Partners LP, and Conor Bastable, as partner of DK Management Partners LP, exercise voting and/or investment control with respect to the shares of Davidson Kempner Distressed Opportunities International. Davidson Kempner Institutional Partners, L.P. owns 88,888 shares. Thomas L. Kempner, Jr. as president of Davidson Kempner Advisers Inc., Stephen M. Dowicz, as treasurer of Davidson Kempner Advisers Inc.,

83

Scott E. Davidson, as principal of Davidson Kempner Advisers Inc., Timothy I. Levart, as corporate secretary of Davidson Kempner Advisers Inc., Robert J. Brivio, Jr., as principal of Davidson Kempner Advisers Inc., Eric P. Epstein, as principal of Davidson Kempner Advisers Inc., Anthony A. Yoseloff, as principal of Davidson Kempner Advisers Inc., Avram Z. Friedman, as principal of Davidson Kempner Advisers Inc., and Conor Bastable, as principal of Davidson Kempner Advisers Inc., exercise voting and/or investment control with respect to the shares of Davidson Kempner Institutional Partners, L.P. Davidson Kempner International, Ltd. owns 101,319 shares. Thomas L. Kempner, Jr. as executive managing member of Davidson Kempner International Advisors, L.L.C., Stephen M. Dowicz, as managing member of Davidson Kempner International Advisors, L.L.C., Scott E. Davidson, as deputy executive managing member of Davidson Kempner International Advisors, L.L.C., Timothy I. Levart, as managing member and chief operating officer of Davidson Kempner International Advisors, L.L.C., Robert J. Brivio, Jr., as managing member of Davidson Kempner International Advisors, L.L.C., Eric P. Epstein, as managing member of Davidson Kempner International Advisors, L.L.C., Anthony A. Yoseloff, as managing member of Davidson Kempner International Advisors, L.L.C., Avram Z. Friedman, as managing member of Davidson Kempner International Advisors, L.L.C., and Conor Bastable, as managing member of Davidson Kempner International Advisors, L.L.C., exercise voting and/or investment control with respect to the shares of Davidson Kempner International, Ltd. Davidson Kempner Partners owns 39,805 shares. Thomas L. Kempner, Jr. as managing partner of MHD Management Co., Stephen M. Dowicz, as general partner of MHD Management Co., Scott E. Davidson, as deputy managing partner of MHD Management Co., Timothy I. Levart, as general partner and chief operating officer of MHD Management Co., Robert J. Brivio, Jr., as general partner of MHD Management Co., Eric P. Epstein, as general partner of MHD Management Co., Anthony A. Yoseloff, as general partner of MHD Management Co., Avram Z. Friedman, as general partner of MHD Management Co., and Conor Bastable, as general partner of MHD Management Co., exercise voting and/or investment control with respect to the shares of Davidson Kempner Partners. M.H. Davidson & Co. owns 5,582 shares. Thomas L. Kempner, Jr. as executive managing member of M.H. Davidson & Co. GP, L.L.C., Stephen M. Dowicz, as managing member of M.H. Davidson & Co. GP, L.L.C., Scott E. Davidson, as deputy executive managing member of M.H. Davidson & Co. GP, L.L.C., Timothy I. Levart, as managing member and chief operating officer of M.H. Davidson & Co. GP, L.L.C., Robert J. Brivio, Jr., as managing member of M.H. Davidson & Co. GP, L.L.C., Eric Epstein, as managing member of M.H. Davidson & Co. GP, L.L.C., Anthony A. Yoseloff, as managing member of M.H. Davidson & Co. GP, L.L.C., Avram Z. Friedman, as managing member of M.H. Davidson & Co. GP, L.L.C., and Conor Bastable, as managing member of M.H. Davidson & Co. GP, L.L.C., exercise voting and/or investment control with respect to the shares of M.H. Davidson & Co. Based on information furnished to us.

(5) Stockholder’s address is 200 West Street, New York, New York 10282.  Information with respect to voting and/or investment control is based on information contained in a Schedule 13g filed by the reporting persons included therein on February 13, 2012.

(6) Stockholder’s address is c/o Aventine Renewable Energy Holdings, Inc., One Lincoln Centre, 5400 LBJ Freeway, Suite 450, Dallas, Texas 75240.

(7) Includes 25,000 shares of restricted stock, which have been granted but have not been issued by our transfer agent and are not currently outstanding. Also includes options to acquire 16,667 shares of common stock which vested on May 5, 2011, 16,667 shares of common stock which will vest in April 2012, and options to acquire 50,000 shares of common stock which vested upon achievement of performance criteria.

(8) Includes 55,576 shares of restricted stock, which have been granted but have not been issued by our transfer agent and are not currently outstanding. Also includes options to acquire 51,300 share of common stock of which 34,200 are vested with the remaining to vest in 2012.  Also includes vested restricted stock units of 26,666.

(9)Includes Restricted Stock Units which vested on March 15, 2011, and April 2012.

(10) Excludes shares held by Senator Global Opportunity Master Fund L.P., of which Mr. Silverman disclaims beneficial ownership.

84

Equity Compensation Plan Information

The following table shows our stockholders approved and non-stockholders approved equity compensation plans as of December 31, 2011:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in first column)
Equity compensation plans approved by security holders	—	—		—
Equity compensation plans not approved by security holders	342,930	$	44.35	236,157
Total	342,930	$	44.35	236,157

The equity compensation plan with outstanding options that has not been approved by our stockholders is our 2010 Equity Incentive Plan.  See Note 19 of our Notes to Consolidated Financial Statements and “Executive Compensation — Summary of Equity Plans” for a description of the material features of the plan. The 2010 Equity Incentive Plan was authorized and established under our Plan.  Our Plan provided that, without any further act or authorization, confirmation of our Plan and entry of the Confirmation Order was deemed to satisfy all applicable federal and state law requirements and all listing standards of any securities exchange for approval by the Board or the stockholders with respect to the 2010 Equity Incentive Plan.  No additional stockholder approval of the plan has been obtained.  The amount shown in the first column consists of 302,738 stock options, 26,858 unvested restricted stock and 13,334 restricted stock units.

Item 13.  Certain Relationships and Related Transactions and Director Independence

Under our Code of Business Conduct and Ethics, employees, officers and directors are required to disclose potential conflicts of interest to our compliance officer or Chief Executive Officer. Potential related person transactions are submitted to the Audit Committee for review. The Audit Committee will consider all relevant facts and circumstances, including the commercial reasonableness of the terms, the benefits, if any, to the Company, opportunity costs of alternate transactions, the materiality and character of the related person’s direct or indirect interest in the transaction and the actual or apparent conflict of interest of the related person, in determining whether to recommend approval or ratification of a transaction. Additionally, under our Code of Business Conduct and Ethics, a director who is deemed to have a potential conflict of interest must recuse himself or herself from any discussions or decisions in the matter under review, and a potential conflict of interest involving an officer with the title of Vice President and above must be approved by our compliance officer or Chief Executive Officer.

There were no related transactions during the year ended December 31, 2011 that were required to be reported pursuant to Item 404(a) of Regulation S-K of the Exchange Act where the procedures described above did not require review, approval or ratification or where these procedures were not followed. In addition, for the year ended December 31, 2011, there has not been any transaction or series of similar transactions, and there is not currently proposed any such transaction, to which the Company was or is a party in which the amount involved exceeded or exceeds $120,000 and in which any of the Company’s directors, executive officers, holders of more than 5% of any class of its voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive Compensation”.

85

The MSCP Funds and Metalmark Capital LLC

Through their previous ownership of Aventine Holdings LLC, the MSCP funds beneficially owned approximately 27.5% of our then outstanding common stock. As a result of the Plan, upon our emergence from bankruptcy the shares of common stock held by the MSCP funds were cancelled and they received 122,519 Warrants. Metalmark Subadvisor LLC, an affiliate of Metalmark Capital LLC, an independent private equity firm established by former principals of Morgan Stanley Capital Partners, manages certain MSCP funds on a subadvisory basis. In January 2008, substantially all of the employees of Metalmark Capital LLC became employees of Citi Alternative Investments, Inc., although Metalmark Capital LLC remained an independent entity owned by those individuals and continued to manage the applicable MSCP funds on a subadvisory basis. Two of our former directors, Messrs. Abramson and Hoffman, were employees of both Metalmark Capital LLC and Citi Alternative Investments, Inc.

Item 14.  Principal Accounting Fees and Services

Fees (including reimbursement for out-of-pocket expenses) to our independent registered public accounting firm for services in 2011 and 2010 were as follows:

	Audit Fees		Audit-Related Fees		Tax Fees		All Other Fees
2011:
Ernst & Young LLP	$	581,479	$	81,873	$	270,551	$	—
2010:
Ernst & Young LLP	$	1,524,546	$	58,500	$	1,012,041	$	—

Audit Fees for 2011 include fees for the audit of the annual financial statements, reviews of the related quarterly statements, and related SEC and other filings.  Audit fees for 2010 include fees for the audit of the annual financial statements and internal control over financial reporting, reviews of the related quarterly statements, and related SEC and other filings.

Tax Fees include fees related to ordinary tax advisory services, tax compliance services and, in 2010, approximately $0.8 million for bankruptcy related tax consultation and services.

The Audit Committee considers the compatibility of non-audit services by its independent registered public accounting firm.

Audit Committee’s Pre-Approval Policies and Procedures

The Audit Committee of the Board reviews and approves the scope of the audit performed by our independent registered public accounting firm and our accounting principles and internal accounting controls.

The Audit Committee’s charter provides that the Audit Committee pre-approve all auditing services, internal control-related services and permitted non-audit services to be performed for the Company by its independent auditor, subject to such exceptions as permitted by applicable laws and regulations.  The Audit Committee is permitted, when appropriate, to delegate this authority to a subcommittee of one or more committee members, provided that decisions of such subcommittee to grant pre-approvals are required to

86

be presented to the full Audit Committee at its next meeting.  100% of such services were pre-approved by the Audit Committee in 2011 and 2010.  The Audit Committee will review such services and approve only those services that are consistent with the SEC’s rules on auditor independence.

PART IV

Item 15.  Exhibits and Financial Statement Schedules

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

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

Consolidated Statements of Operations — For the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009.

Consolidated Balance Sheets — December 31, 2011 and 2010.

Consolidated Statements of Stockholders’ Equity (Deficit) — For the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009.

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

See the Exhibit Index beginning on page 90 for a list of the exhibits being filed or furnished with or incorporated by reference into this Annual Report on Form 10-K.

87

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 Dallas, State of Texas, on the 8th day of March, 2012.

AVENTINE RENEWABLE ENERGY HOLDINGS, INC.
	By:	/s/ Calvin Stewart
		Name:  Calvin Stewart
		Title:  Chief Financial Officer
		(Principal Financial and 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/ John W. Castle	Chief Executive Officer (Principal Executive Officer)	March 8, 2012
John W. Castle
By:	/s/ Calvin Stewart	Chief Financial Officer	March 8, 2012
Calvin Stewart
By:	/s/ Eugene I. Davis	Chairman of the Board of Directors	March 8, 2012
Eugene I. Davis
By:	/s/ Timothy J. Bernlohr	Director and Chairman of the Compensation Committee	March 8, 2012
Timothy J. Bernlohr
By:	/s/ Kurt M. Cellar	Director and Chairman of the Audit Committee	March 8, 2012
Kurt M. Cellar
By:	/s/ Douglas Silverman	Director	March 8, 2012
Douglas Silverman
By:	/s/ Carney Hawks	Director	March 8, 2012
Carney Hawks

88

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

As of the date of filing of this Annual Report on Form 10-K, no annual report to security holders covering the registrant’s last fiscal year, proxy statement, form of proxy or other proxy soliciting material sent to more than 10 of the registrant’s security holders with respect to any annual or other meeting of security holders has been sent to security holders.

89

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Statements of Operations

	Successor						Predecessor
	Year Ended December 31,			Ten Months Ended December 31,			Two Months Ended February 28,			Year Ended December 31,
	2011			2010			2010			2009
	(In thousands except per share amounts)
Net sales	$	887,587		$	370,559		$	77,675		$	594,623
Cost of goods sold	(857,377		)	(349,751		)	(66,686		)	(585,904		)
Gross profit	30,210			20,808			10,989			8,719
Selling, general and administrative expenses	(32,714		)	(34,068		)	(4,608		)	(26,694		)
Start-up activities	—			(1,177		)	—			—
Other expense	(3,329		)	(1,681		)	(515		)	(1,510		)
Operating income (loss)	(5,833		)	(16,118		)	5,866			(19,485		)
Income from termination of marketing agreements	—			—			—			10,176
Interest income	63			139			—			11
Interest expense	(24,186		)	(8,274		)	(1,422		)	(14,697		)
Gain (loss) on derivative transactions, net	(4,424		)	633			—			1,219
Loss on available-for-sale securities	(510		)	(1,990		)	—			—
Loss on early extinguishment of debt	(10,038		)	—			—			—
Other non-operating income	2,074			117			—			—
Income (loss) before reorganization items and income taxes	(42,854		)	(25,493		)	4,444			(22,776		)
Reorganization items	—			—			(20,282		)	(32,440		)
Gain due to plan effects	—			—			136,574			—
Loss due to fresh start accounting adjustments	—			—			(387,655		)	—
Loss before income taxes	(42,854		)	(25,493		)	(266,919		)	(55,216		)
Income tax (expense) benefit	(536		)	29			626			8,956
Net loss	$	(43,390	)	$	(25,464	)	$	(266,293	)	$	(46,260	)
Loss per common share — basic	$	(4.80	)	$	(2.97	)	$	(6.14	)	$	(1.08	)
Basic weighted-average number of shares	9,047			8,584			43,401			42,968
Loss per common share — diluted	$	(4.80	)	$	(2.97	)	$	(6.14	)	$	(1.08	)
Diluted weighted-average number of common and common equivalent shares	9,047			8,584			43,401			42,968

See notes to consolidated financial statements.

F-1

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Balance Sheets

	December 31,
	2011			2010
	(In thousands, except share and per share data)
Assets
Current assets:
Cash and equivalents	$	36,105		$	34,533
Restricted cash	—			164,765
Short term investments	191			—
Accounts receivable, net of allowance for doubtful accounts of $174 in 2011 and $75 in 2010	16,578			11,571
Inventories	43,297			44,179
Income taxes receivable	4			954
Prepaid expenses and other current assets	7,732			14,185
Total current assets	103,907			270,187
Property, plant and equipment, net	295,599			296,289
Restricted cash	—			16,211
Other assets	14,732			11,291
Total assets	$	414,238		$	593,978
Liabilities and Stockholders’ Equity
Current liabilities:
Current maturities of long-term debt	$	2,283		$	157,718
Current obligations under capital leases	348			789
Accounts payable	14,266			23,311
Accrued liabilities	3,621			4,906
Other current liabilities	12,817			10,589
Total current liabilities	33,335			197,313
Long-term debt	214,051			190,239
Deferred tax liabilities	2,078			2,026
Other long-term liabilities	6,093			2,742
Total liabilities	255,557			392,320
Stockholders’ equity:
Common stock, par value $0.001 per share; (15,000,000 shares authorized; 8,346,271 shares outstanding, net of 74,841 shares held in treasury at December 31, 2011: 7,448,916 shares outstanding, net of 7,791 shares held in treasury at December 31, 2010)	8			8
Preferred stock; (5,000,000 shares authorized; no shares issued or outstanding)	—			—
Additional paid-in capital	231,744			227,360
Retained deficit	(68,854		)	(25,464		)
Accumulated other comprehensive income (loss), net	(4,217		)	(246		)
Total stockholders’ equity	158,681			201,658
Total liabilities and stockholders’ equity	$	414,238		$	593,978

See notes to consolidated financial statements.

F-2

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity (Deficit)

	Treasury Shares		Common Shares		Common Stock			Additional Paid-In Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income/(Loss)			Total Stockholders’ Equity
	(In thousands)
Predecessor
Predecessor balance at December 31, 2008	21,548,640		42,970,988		$	43		$	292,984		$	17,839		$	(2,070	)	$	308,796
Tax effect of exercised and lapsed stock options			(4,830	)				(1,242		)							(1,242		)
Stock option exercises (forfeitures)			85,000		1			19									20
Stock-based compensation								2,536									2,536
Forfeiture of non-vested restricted stock			(3,000	)													—
Comprehensive loss:
Net loss											(46,260		)				(46,260		)
Pension and postretirement liability adjustment, net of tax														773			773
Unrealized holding gain on available-for-sale securities, net of tax														2,909			2,909
Total comprehensive loss																	(42,578		)
Predecessor balance at December 31, 2009	21,548,640		43,048,158		$	44		$	294,297		$	(28,421	)	$	1,612		$	267,532
Stock option exercises (forfeitures)								330									330
Stock-based compensation								43									43
Comprehensive loss:
Net loss											(266,293		)				(266,293		)
Pension and postretirement liability adjustment, net of tax														(3		)	(3		)
Unrealized holding gain on available-for-sale securities, net of tax														765			765
Total comprehensive loss																	(265,531		)
Cancellation of Predecessor common stock	(21,548,640	)	(43,048,158	)	(44		)										(44		)
Reorganization and fresh start accounting adjustments								(294,670		)	294,714			(2,374		)	(2,330		)
Issuance of equity in connection with emergence from bankruptcy			6,614,980		8			219,916									219,924
Successor balance at February 28, 2010	—		6,614,980		$	8		$	219,916		$	—		$	—		$	219,924
Successor
Stock-based compensation			83,038					7,784									7,784
Issuances of common stock			758,321														—
Warrants exercised			368					15									15
Repurchases of common stock	7,791							(355		)							(355		)
Comprehensive loss:
Net loss											(25,464		)				(25,464		)
Pension and postretirement liability adjustment, net of tax														(246		)	(246		)
Total comprehensive loss																	(25,710		)
Successor balance at December 31, 2010	7,791		7,456,707		$	8		$	227,360		$	(25,464	)	$	(246	)	$	201,658
Stock option exercises (forfeitures)			29,064					339									339
Warrants exercised			130					5									5
Stock-based compensation			32,536					4,912									4,912
Issuances of common stock			902,675														—
Purchase of treasury stock	67,050							(1,055		)							(1,055		)
Issuance of stock units								183									183
Comprehensive loss:
Net loss											(43,390		)				(43,390		)
Pension and postretirement liability adjustment, net of tax														(3,971		)	(3,971		)
Total comprehensive loss																	(47,361		)
Successor Balance at December 31, 2011	74,841		8,421,112		$	8		$	231,744		$	(68,854	)	$	(4,217	)	$	158,681

See notes to consolidated financial statements.

F-3

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	Successor						Predecessor
	Year Ended December 31, 2011			Ten Months Ended December 31, 2010			Two Months Ended February 28, 2010			Year Ended December 31, 2009
	(In thousands)
Net loss	$	(43,390	)	$	(25,464	)	$	(266,293	)	$	(46,260	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Non-cash gain due to Plan effects	—			—			(136,574		)	—
Non-cash loss due to fresh start accounting adjustments	—			—			387,655			—
Provision for rejected executory contracts and leases	—			—			9,590			26,403
Unrealized/realized loss on available-for-sale securities	510			1,990			—			—
Depreciation and amortization	27,868			9,792			2,795			16,709
Deferred income taxes	—			(910		)	—			(2,610		)
Stock-based compensation expense	5,434			7,784			277			2,536
Loss on renewable identification numbers	117			—			—			—
Loss on early retirement of debt	10,038			—			—			—
Gain on legal settlements	(1,462		)	—			—			—
Other	25			76			—			(1,000		)
Changes in operating assets and liabilities:
Accounts receivable, net	(5,007		)	(4,483		)	2,560			44,941
Income tax receivable	145			5,022			—			9,339
Inventories	882			(18,960		)	1,543			61,184
Prepaid expenses and other current assets	4,117			(9,972		)	1,339			2,876
Other assets	(185		)	6,284			—			(16,921		)
Accounts payable	(8,285		)	3,805			7,061			(61,988		)
Other long-term liabilities	706			5,831			(21,640		)	5,607
Net cash provided by (used in) operating activities	(8,487		)	(19,205		)	(11,687		)	40,816
Investing Activities
Additions to property, plant and equipment, net	(23,330		)	(77,672		)	(2,086		)	(2,279		)
Canton, Illinois facility acquisition	—			(16,880		)	—			—
Other	—			—			—			2,000
Net cash used in investing activities	(23,330		)	(94,552		)	(2,086		)	(279		)
Financing Activities
Proceeds from issuance of debt	25,000			—			—			—
Repayment of senior secured notes	(155,000		)	—			—			—
Payment of term loan	(2,188		)	—			—			—
Proceeds from the issuance of senior secured term loan credit agreement, net of original issuance discount of $8,000	—			192,000			—			—
Proceeds from issuance of senior secured notes	—			50,750			98,119			—
Decrease/(Increase) in restricted cash	180,976			(165,692		)	(7,833		)	—
Penalty on early retirement of debt	(8,350		)	—			—			—
Debt issuance costs	(5,193		)	(8,162		)	(1,190		)	—
Repayment of note payable	(28		)	(5,252		)	—			—
Net repayments on revolving credit facilities	—			—			(27,765		)	(24,435		)
Borrowings from (repayments of) debtor-in-possession debt facility	—			—			(15,000		)	15,000
Payments on other long-term debt and capital lease obligations	(778		)	(253		)	—			—
Financing fees and expenses paid pre-petition	—			—			—			(1,876		)
Proceeds from warrants exercised	5			15			—			—
Proceeds from stock option exercises	—			—			96			20
Purchase of treasury shares	(1,055		)	(355		)	—			—
Net cash provided by (used in) financing activities	33,389			63,051			46,427			(11,291		)
Net increase (decrease) in cash and equivalents	1,572			(50,706		)	32,654			29,246
Cash and equivalents at beginning of the period	34,533			85,239			52,585			23,339
Cash and equivalents at end of the period	$	36,105		$	34,533		$	85,239		$	52,585
Supplemental disclosure of cash flow:
Interest paid	$	23,747		$	13,488		$	1,750		$	6,040
Income taxes paid (refunded)	$	372		$	32		$	822		$	(16,408	)

See notes to consolidated financial statements.

F-4

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

1.         Organization and Basis of Presentation

Organization

Aventine Renewable Energy Holdings, Inc. and its subsidiaries (collectively referred to as “Aventine” or the “Company”) is a producer and marketer of ethanol.  The Company’s production facilities produced 248.7 million gallons of ethanol in 2011 and 186.4 million gallons of ethanol in 2010.  In addition to producing ethanol, the Company’s 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 grain distillers dried yeast.  During 2011 and 2010, Aventine marketed and distributed a total of 257.5 million and 184.0 million gallons of ethanol, respectively.

Basis of Presentation

The accompanying consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). All material intercompany transactions and balances have been eliminated. Any material events or transactions that occurred subsequent to December 31, 2011, through the date of filing of this Annual Report on Form 10-K were reviewed for purposes of determining whether any adjustments or additional disclosures were required to be made to the accompanying consolidated financial statements.

As a result of its bankruptcy filing during 2009, the Company applied the authoritative guidance of ASC 852, Reorganizations (“ASC 852”), in preparing the consolidated financial statements through February 28, 2010 (the “Convenience Date”).  See Note 2.

The accompanying consolidated financial statements for the prior period contain certain reclassifications to conform to the presentation used in the current period.  The reclassifications had no impact on stockholders’ equity, working capital, gross profit or net income.

Segments

Aventine operates in one reportable segment, the manufacture and marketing of fuel-grade ethanol.

Liquidity Outlook

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

Our principal sources of liquidity are cash and cash equivalents, cash provided by our borrowing facility, and cash provided by operations. At December 31, 2011, we had $36.1 million of cash and cash equivalents and $70.6 million in net working capital.  Additionally, at December 31, 2011, we had

F-5

availability under the New Revolving Facility of approximately $20.1 million. We currently depend on the New Revolving Facility for future working capital needs. If there is an event of default by us under the New Revolving Facility that continues beyond any applicable cure period, resulting in amounts outstanding becoming immediately due and payable, or if our qualifying inventory and accounts receivable decline such that our borrowing base is limited, we may not have sufficient funds available to repay such borrowings or we may be unable to borrow a sufficient amount to fund our operations.  In the event that cash flows and borrowings under the New Revolving Facility are not sufficient to meet our cash requirements, we may be required to seek additional financing.

Our liquidity position is significantly influenced by our operating results, which in turn are substantially dependent on commodity prices, especially prices for corn, ethanol, natural gas, and unleaded gasoline. As a result, adverse commodity price movements adversely impact our liquidity. Often, movements in commodity prices are well correlated such that increases or decreases in commodities movements provide a predictable change in our liquidity.  However, in the last three years, there have been periods of time in which other economic factors cause a significant deterioration in commodity price correlations such that our ability to predict our liquidity level may be significantly diminished.  Accordingly, we can provide no assurance that the amounts of cash available from operations, together with the New Revolving Facility, will be sufficient to fund our operations.

Our principal uses of liquidity are payments related to our outstanding debt and liquidity facility, working capital, funding of operations, and capital expenditures. Under our Term Loan Agreement (as defined below), we are required to maintain a minimum liquidity position of $15 million comprised of available cash and borrowing capacity under our New Revolving Facility throughout 2011 and 2012, and $25 million beginning in 2013.  Based on current commodity prices and market conditions, our liquidity forecast may indicate a need to defer start up of our Aurora West facility and our Canton facility beyond 2012.  If we do not generate enough cash flow from operations to satisfy our principal uses of liquidity, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt, selling assets, reducing or delaying capital investments or raising additional capital. However, under our Term Loan Agreement , we are required to maintain a debt to total capitalization ratio of no greater than .65 to 1.0. There is no assurance that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations.

Despite the risks identified associated with our liquidity and our forecasted operating cash flows, we believe that we have sufficient liquidity through our cash and cash equivalents, cash from operations and borrowing capacity under our New Revolving Facility to meet our short-term and long-term normal recurring operating needs, debt service obligations, contingencies, and anticipated capital expenditures through 2012 and beyond.  We also believe that the additional avenues available to preserve liquidity in the event of an industry or economic downturn are adequate to allow us to continue operations.

2.         Bankruptcy Proceedings and Related Events

On April 7, 2009 (the ‘‘Petition Date’’), Aventine and all of its direct and indirect subsidiaries (collectively, the ‘‘Debtors’’), filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) with the United States Bankruptcy Court for the District of Delaware (the ‘‘Bankruptcy Court’’). The Debtors filed their First Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code on January 13, 2010 (as modified, the ‘‘Plan’’). The Plan was confirmed by order entered by the Bankruptcy Court on February 24, 2010 (the ‘‘Confirmation Order’’), and became effective on March 15, 2010 (the ‘‘Effective Date’’), the date on which the Company emerged from protection under Chapter 11 of the Bankruptcy Code.  ASC 852, which is applicable to companies in Chapter 11 proceedings, generally does not change the manner in which financial statements are prepared while the company remains in Chapter 11 proceedings. However, ASC 852 does require that the financial statements for periods subsequent to the filing of a Chapter 11 petition and prior to the Effective Date

F-6

distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Revenues, expenses (including professional fees), realized gains and losses, and provisions for losses that can be directly associated with the reorganization and restructuring of the business must be reported separately as reorganization items in the consolidated statements of operations. The consolidated balance sheet must distinguish pre-petition liabilities subject to compromise from both those pre-petition liabilities that are not subject to compromise and from post-petition liabilities. Liabilities that may be affected by the Plan must be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. In addition, cash provided by reorganization items must be disclosed separately in the condensed consolidated statement of cash flows. ASC 852 became effective for Aventine on April 7, 2009, and Aventine segregated those items, as outlined above, for all applicable reporting periods subsequent to such date through the Effective Date.

Until emergence on the Effective Date, the Debtors were operating as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. In general, as debtors-in-possession, the Debtors were authorized to continue to operate as ongoing businesses, but could not engage in transactions outside the ordinary course of business without the approval of the Bankruptcy Court.

The consolidated financial statements prior to March 1, 2010 reflect results based upon the historical cost basis of the Company while the post-emergence consolidated financial statements reflect the new basis of accounting incorporating the fair value adjustments made in recording the effects of fresh-start reporting. Therefore, the post-emergence periods are not comparable to the pre-emergence periods. As a result of the application of fresh start accounting, the Company’s consolidated financial statements prior to and including February 28, 2010, represent the operations of its pre-reorganization predecessor company and are presented separately from the consolidated financial statements of its post-reorganization successor company.

The term “Predecessor” refers only to the Company and its subsidiaries prior to the Effective Date, and the term “Successor” refers only to the Company and its subsidiaries subsequent to the Effective Date. Unless the context indicates otherwise, the terms “Aventine” and the “Company” are used interchangeably in this Annual Report on Form 10-K to refer to both the Predecessor and Successor Company.

Chapter 11 Reorganization Items

ASC 852 requires separate disclosure of reorganization items such as realized gains and losses from the settlement of pre-petition liabilities, provisions for losses resulting from the reorganization and restructuring of the business, as well as professional fees directly related to the process of reorganizing the Debtors under Chapter 11.

F-7

The Debtors’ reorganization items consisted of the following:

	Predecessor
	For the Two Months Ended February 28, 2010		For the Year Ended December 31, 2009
	(In thousands)
Provision for rejected executory contracts and other accruals	$	9,590	$	26,403
Professional fees directly related to reorganization (1)	8,776		7,449
Other (2)	1,916		(1,412		)
Total reorganization items	$	20,282	$	32,440

(1)Includes post-petition fees associated with advisors to the Debtors, the statutory committee of unsecured creditors and certain secured creditors.

(2)Includes gains on the settlement of pre-petition critical vendor claims for less than amounts owed and other adjustments.

Pre-petition liabilities subject to compromise

Pre-petition liabilities subject to compromise refers to unsecured obligations that will be accounted for under a plan of reorganization.  Generally, actions to enforce or otherwise effect payment of pre-Chapter 11 liabilities are stayed.  ASC 852 requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts.  These liabilities represent the estimated amount expected to be allowed on known or potential claims to be resolved through the Chapter 11 process, and remain subject to future adjustments arising from negotiated settlements, actions of the Bankruptcy Court, rejection of executory contracts and unexpired leases, the determination as to the value of any potential collateral securing the claims, proofs of claim, or other events. Pre-petition liabilities subject to compromise also include certain items that may be assumed under the plan of reorganization, and as such, may be subsequently reclassified to liabilities not subject to compromise.

Pre-petition liabilities subject to compromise consisted of the following at December 31, 2009:

	Predecessor
	December 31, 2009
	(In thousands)
10% senior unsecured notes due 2017 (see Note 11)	$	300,000
Provision for rejected executory contracts and other accruals	26,403
Pre-petition accounts payable	29,451
Accrued interest on notes payable	15,500
Unamortized issuance costs of 10% senior unsecured notes	(5,805		)
Total pre-petition liabilities subject to compromise	$	365,549

Pre-petition liabilities not compromised

The pre-petition liabilities not compromised of $11.5 million at December 31, 2009, consisted of pre-petition accounts payable secured by liens, and pre-petition payables which are priority claims and will be paid in full. Such amounts were recorded in “Other long-term liabilities” on the consolidated balance sheet.

F-8

Fresh Start Accounting and Selection of Convenience Date

The Company emerged from bankruptcy on March 15, 2010. In accordance with ASC 852, the Company adopted fresh start accounting and adjusted the historical carrying value of its assets and liabilities to their respective fair values at the Effective Date. Simultaneously, the Company determined the fair value of its equity at the Effective Date. The Company selected an accounting convenience date proximate to the Effective Date for purposes of making the aforementioned adjustments to historical carrying values, because the activity between the Effective Date and the Convenience Date does not result in a material difference in the results. The Company selected a Convenience Date of February 28, 2010. As a result, the Company recorded fresh start accounting adjustments to historical carrying values of assets and liabilities as of February 28, 2010, using market prices, discounted cash flow methodologies based primarily on observable market information and, to a lesser extent, on unobservable market information, and other techniques. The fresh start accounting adjustments are reflected in the balance sheet at February 28, 2010 and in the statement of operations for the two months ended February 28, 2010.  The Company’s consolidated statement of operations for the ten months ended December 31, 2010, reflects the results of successor operations.

The Company’s adoption of fresh start accounting resulted in the Company becoming a new entity as of the Effective Date, with a new capital structure, a new accounting basis in the identifiable assets and liabilities assumed and no retained earnings or accumulated losses. The consolidated financial statements on or after March 1, 2010, are not comparable to the consolidated financial statements prior to that date. The financial statements for the periods ended prior to February 28, 2010, do not include the effect of any changes in the Company’s capital structure or changes in the fair value of assets and liabilities as a result of fresh start accounting.

Fresh start accounting provides, among other things, for a determination of the value to be assigned to the equity of the emerging company as of the Effective Date. Reorganization equity value represents the Company’s estimate of the amount a willing buyer would pay for the Company’s net assets immediately after the reorganization. This amount, approximately $219.9 million, was determined by Company management, who developed the enterprise value using a combination of the following three measurement methodologies: 1) comparable public company analysis, 2) discounted cash flow analysis, and 3) precedent transactions analysis. This amount was determined based, in part, on economic, competitive, and general business conditions prevailing at the time. As noted above, enterprise value, including the assumptions referred to below, was in turn used to determine the equity value of the Company at the Effective Date. The enterprise value of the Company was estimated between $220.0 million and $260.0 million, less an assumed estimated total net debt of $28.9 million, for an equity value of the Company estimated between $191.1 million and $231.1 million, with a midpoint equity value of $211.1 million.  Assumed estimated total net debt includes $105 million principal amount of 13% senior secured notes due 2015 (the “Notes”) issued pursuant to the Plan on the Effective Date and a $5.3 million note payable due to Kiewit Energy Company (‘‘Kiewit’’) as partial satisfaction of Kiewit’s secured claim on the Aurora West ethanol expansion facility (the “Kiewit Note”) and unrestricted cash of $81.4 million.

In estimating the range of enterprise values and equity value of the Company at the time of emergence, management considered the following:

·historical financial information of the Debtors for recent years and interim periods;

·internal financial and operating data of the Company, including financial projections prepared by management relating to the Company’s business and prospects;

·interviews with senior management;

·publicly available financial data and market value of comparable public companies management deemed generally comparable to the operating business of the Company;

F-9

·relevant precedent transactions in the ethanol industry—for purposes of this analysis management analyzed all sale transactions of ethanol facilities occurring from January 1, 2009, through November 15, 2009, for which purchase prices were publicly disclosed and were not subject to extraordinary forces making them not relevant to this valuation (i.e., cold idled facilities sold for scrap value);

·competitive bids received from various third parties;

·certain economic and industry information relevant to the operating business; and

·other studies, analyses, inquiries, and investigations as management deemed appropriate.

Descriptions of the three different valuation methodologies, the comparable public company analysis, the precedent transaction analysis and the discounted cash flow approach, are as provided below.

Comparable Public Company Analysis

A comparable public company analysis estimates value based on a comparison of the target company’s financial statistics with the financial statistics of public companies that are similar to the target company. It establishes a benchmark for asset valuation by deriving the value of ‘‘comparable’’ assets, standardized using a common variable such as revenues, earnings, cash flows and operating capacity. The analysis includes a detailed multi-year financial comparison of each company’s income statement, balance sheet, cash flow statement and operating capacity. In addition, each company’s performance, profitability, margins, leverage and business trends are also examined. Based on these analyses, a number of financial multiples and ratios are calculated to gauge each company’s relative performance and valuation.

Precedent Transactions Analysis

Precedent transactions analysis estimates value by examining publicly announced merger and acquisition transactions. An analysis of the disclosed purchase price as a multiple of various operating statistics (particularly total annual production capacity in the case of the ethanol industry) reveals industry acquisition multiples for companies in similar lines of businesses to the Company. These transaction multiples are calculated based on the purchase price (including any debt assumed) paid to acquire companies that are comparable to the Debtors. These multiples are then applied to the Debtors’ annual production capacity to determine the total enterprise value or value to a potential buyer.

The transactions selected were based on the following criteria:

·deals announced since September 2008 for targets in the United States and Canada;

·deal was closed prior to November 2009;

·majority stake acquired;

·target company is an ethanol producer;

·transactions with extraordinary circumstances regarding the plants were excluded; and

·implied enterprise value / capacity could be determined.

Discounted Cash Flow Approach

The discounted cash flow (‘‘DCF’’) valuation methodology relates the value of an asset or business to the present value of expected future cash flows to be generated by that asset or business. The DCF methodology is a ‘‘forward looking’’ approach that discounts the expected future cash flows by a theoretical or observed discount rate determined by calculating the weighted average cost of debt and equity capital (‘‘WACC’’) for publicly traded companies that are similar to the Debtors. The expected future cash flows have two components: the present value of the projected unlevered after-tax free cash flows for a determined period and the present value of the terminal value of cash flows (representing firm value beyond the time horizon of the financial projections). The projected cash flows were discounted from

F-10

the financial projections using the Debtors’ estimated WACC, and the terminal value of the Debtors was calculated using a per gallon multiple of operating capacity as is consistent with industry practice.

In its efforts to value the Debtors, a DCF was conducted under the following assumptions:

·Company-provided earnings before interest, taxes, depreciation, amortization and reorganization levels;

·WACC of 20% based on an analysis of the Notes term sheet, required private equity returns in similar companies and required returns of other publicly traded ethanol producers;

·Exit multiple of $1.00 per gallon of operating capacity plus consideration for working capital (projected working capital balance as of December 31, 2014, discounted at the Debtors’ WACC) as is consistent with industry practice;

·Corporate tax rate of 40%; and

·The two uncompleted facilities (Aurora West and Mt. Vernon) are completed by the end of 2011.

Under this set of assumptions, management placed an enterprise value of the Company ranging from approximately $220.0 million to $260.0 million.

In performing the comparable public company analysis, it was determined that only one publicly available ethanol company is generally comparable to the Company. Several ethanol producers were deemed not comparable or not usable for the purposes of the valuation because (i) their equity is privately held; (ii) ethanol production makes up less than 10% of sales, and/or (iii) the companies are distressed. For this reason, it was determined that the DCF analysis and precedent transactions analysis were the most pertinent valuation methodologies for the purpose of valuing the Company. Accordingly, the DCF analysis and the precedent transactions analysis were each weighted at 40% and the comparable companies’ analysis was weighted at 20% in estimating the Company’s enterprise value.

The Company’s reorganization value was determined employing the following weighting of three valuation methodologies and their related estimated valuations:

	Weighting		Enterprise Value
Discounted Cash Flow	40	%	$0.80 to $0.90 / gallon (for operational facilities);
			$0.63 to $0.73 / gallon (for uncompleted facilities)
Precedent Transactions	40	%	WACC of 20.0% and $1.00 per gallon terminal multiple
			plus consideration for working capital.
Market Multiples	20	%	$0.95 to $1.05 / gallon (for operational facilities);
			$0.75 to $0.85 / gallon (for uncompleted facilities)

Enterprise value is calculated excluding cash and therefore the implied indication of value also excludes cash.

F-11

			Enterprise Value Range
	Weighting		Low		Mid		High
Discounted Cash Flow	40	%	$	220.0	$	240.0	$	260.0
Precedent Transactions	40	%	$	200.0	$	220.0	$	240.0
Market Multiples	20	%	$	240.0	$	260.0	$	280.0
Weighted Average Enterprise Valuation Range			$	220.0	$	240.0	$	260.0
Enterprise Value / Completed Gallons			$	1.06	$	1.16	$	1.26
Enterprise Value / Total Gallons (1)			$	0.51	$	0.55	$	0.60

(1)Assumes completion of Mt. Vernon and Aurora West facilities.

In forecasting the Debtor’s five year business plan, management made a number of assumptions with respect to the Company’s operations, market prices and margins. The Company’s estimate of reorganization value assumes the achievement of the future financial results contemplated in its forecasted cash flows based on the assumptions above, and there can be no assurance that the Company will realize that value. The estimates and assumptions used are subject to significant uncertainties, many of which are beyond the Company’s control, and there is no assurance that anticipated financial results will be achieved. Assumptions used in the Company’s DCF analysis that have the most significant effect on its estimated reorganization value include:

·Mt. Vernon begins construction in the second quarter of 2010 and begins production in the fourth quarter of 2010.

·Aurora West begins construction in the second quarter of 2011 and begins production in the first quarter of 2012. Post-emergence management accelerated construction of Aurora West and it is mechanically complete as of December 2010 and is expected to become operational in the spring of 2011. However, any impact on reorganization value of this accelerated construction, positive or negative, would depend on the consistency of a number of other assumptions.

·Kiewit is assumed to be paid $11.9 million in March 2010 and receive a non-recourse secured note for the remaining amount of their claim with an interest rate of 5.0% (matures at the earlier of five years after emergence or six months after the completion of Aurora West). In post-emergence, the non-recourse secured note was paid off in the second quarter of 2010.

·Fourth quarter 2011 estimated corn prices extended through projection horizon.

·Fourth quarter 2011 estimated natural gas prices extended through projection horizon.

·$5.0 million of pre-petition accounts payable and $10.0 million of transaction fees paid at emergence.

·An additional $50.0 million note assumed to be issued upon the resumption of construction at Aurora West on substantially similar terms to the Notes.

·Margins were assumed to be consistent with actual margins being experienced at the time for the fourth quarter of 2009 and the first quarter of 2010 and somewhat more conservative margins were employed in future years based on the trends at the time.

Upon emergence, there were 8.55 million shares of new common equity available for issuance with a book value of $24.69 per share. Of the 8.55 million shares, 1.71 million were issued to the subscribers to the $105 million aggregate principal amount of the Notes, while 6.84 million shares were reserved specifically for distribution to holders of general unsecured claims (including the holders of the Company’s pre-petition $300 million of unsecured notes) in settlement of their claims. At December 31, 2011, the Company had issued approximately 6.4 million shares, with approximately 0.4 million shares remaining to be distributed to holders of general unsecured claims.

The balance sheet reorganization adjustments presented below summarize the impact of the Plan and the adoption of fresh start accounting as of February 28, 2010.

F-12

AVENTINE RENEWABLE ENERGY HOLDINGS, INC. AND SUBSIDIARIES

REORGANIZED CONDENSED CONSOLIDATED BALANCE SHEET

	February 28, 2010
	Predecessor			Reorganization Adjustments			(1)	Fresh Start Adjustments				Successor
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	66,866		$	18,373		(2)	$	—			$	85,239
Accounts receivable	8,163			(1,000		)	(3)	—				7,163
Inventories	22,694			—				2,526			(12)	25,220
Income taxes receivable	5,975			—				—				5,975
Prepaid expenses and other current assets	5,423			(1,210		)	(4)	—				4,213
Total current assets	109,121			16,163				2,526				127,810
Property, plant and equipment, net	587,103			1,700			(2)	(379,970		)	(12)	208,833
Restricted cash	7,452			7,832			(2)	—				15,284
Available for sale securities	6,207			—				—				6,207
Other assets	9,860			734			(5)	(4,423		)	(12)	6,171
Total assets	$	719,743		$	26,429			$	(381,867	)		$	364,305
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Short-term borrowings	$	42,765		$	(37,513	)	(2),(6)	$	—			$	5,252
Accounts payable	16,588			1,637			(7)	1,281			(12)	19,506
Accrued liabilities	2,327			—				—				2,327
Other current liabilities	6,837			—				—				6,837
Total current liabilities	68,517			(35,876		)		1,281				33,922
Pre-petition liabilities subject to compromise	358,790			(358,790		)	(9)	—				—
Long-term debt	—			98,119			(2)	6,881			(12)	105,000
Deferred tax liabilities	2,936			—				—				2,936
Other long-term liabilities	31,069			(28,545		)	(10)	—				2,524
Total liabilities	461,312			(325,092		)		8,162				144,382
STOCKHOLDERS’ EQUITY
Common stock	44			(37		)	(11)	—				7
Additional paid-in capital	294,670			(74,754		)	(11)	—				219,916
Retained earnings (deficit)	(38,657		)	426,312			(11)	(387,655		)	(13)	—
Accumulated other comprehensive income	2,374			—				(2,374		)	(13)	—
Total shareholders’ equity	258,431			351,521				(390,029		)		219,923		(8)
Total liabilities and stockholders’ equity	$	719,743		$	26,429			$	(381,867	)		$	364,305

F-13

Explanatory Notes

(1) Reorganization adjustments represent amounts recorded on the Effective Date for the implementation of the Plan, including the settlement of liabilities subject to compromise and related payments, the issuance of new debt and repayment of old debt, distributions of cash and new shares of common stock, and the cancellation of Predecessor’s common stock.

(2)   Cash effects of the Plan (in thousands):

Proceeds from issuance of senior secured 13% notes due March 2015	$	98,119
Payment of principal on secured revolving credit facility with JPMorgan Chase Bank	(27,765		)
Payment of interest and fees on secured revolving credit facility with JPMorgan Chase Bank	(206		)
Payment of principal on debtor-in-possession debt facility	(15,000		)
Payment of interest on debtor-in-possession debt facility	(96		)
Payment of secured claims to Kiewit on expansion projects in Aurora, Nebraska and Mt. Vernon, Indiana	(17,931		)
Represents payment to Applied Process Technology International LLC for license agreements which provide the Company with all of the rights to the Delta-T Technology necessary to construct and operate the ethanol expansion facilities at Aurora West and Mt. Vernon	(1,700		)
Fund additional restricted cash	(7,832		)
Payments of priority and other secured claims and cure amounts	(4,876		)
Payment of professional fees	(4,340		)
Net change in cash and cash equivalents	$	18,373

This entry records the proceeds from the issuance of the Notes and the payment of certain bankruptcy obligations in accordance with the Plan. Cash of $7.8 million reclassified to restricted cash represents amounts held in escrow accounts pending final resolution from the Bankruptcy Court.

(3)  The Company offset $1.0 million of receivables from a certain customer against $1.7 million of payables due to the same counterparty, resulting in a net payout of $0.7 million to the customer/vendor, also discussed in footnote (7) below.

(4)   Represents the write-off of the prepaid directors and officers insurance balance for the predecessor company of $1.6 million, plus $0.3 million reclassification of debt issuance costs related to the issuance of the Notes and the secured revolving credit facility with PNC Bank (see Note 9) to Other Assets, offset by the addition of a deposit on title insurance pertaining to the Aurora West expansion facility of $0.7 million.

(5)  Represents the $0.7 million of debt issuance costs pertaining to the Notes and the secured revolving credit facility (see Note 9), of which $0.3 million was reclassified from Prepaid Expenses and Other Current Assets.

(6)  As noted above in explanatory note (2), the Company paid in full the $27.8 million pre-petition secured revolving credit facility and the $15.0 million debtor-in-possession loan, including $0.3 million representing all respective accrued interest on said loans, in accordance with the Plan. Offsetting these reductions in debt, the Company issued a $5.3 million note payable due to Kiewit as partial satisfaction of Kiewit’s secured claim on the Aurora West ethanol expansion facility.

(7)   The increase consisted of $1.6 million of accrued priority, secured, and cure amounts not yet paid to claimants, $0.7 million of accrued Class 7 convenience claims also not yet paid to claimants, the $1.0 million accrued professional fee payable to a court-appointed financial advisor, all of which was offset

F-14

by a $1.7 million reduction in payable due to a certain vendor/customer as discussed in footnote (3) above.

(8)  Reconciliation of enterprise value to determination of equity (in thousands):

Total enterprise value	$	240,000
Successor company cash balance at February 28, 2010	85,239
Accrued plan effects payments	(5,348		)
Kiewit note	(5,252		)
Restricted cash available upon emergence	10,284
Fair value of senior secured notes due March 15, 2015	(105,000		)
Total shareholders’ equity	$	219,923

(9) Represents the disposition of liabilities subject to compromise (in thousands):

Liabilities subject to compromise discharged at emergence:
Accrued interest	$	8,215
10% senior unsecured notes due 2017	159,000
Class 6 General Unsecured Claims	24,958
Class 7 Convenience Claims	1,302
Total liabilities subject to compromise discharged at emergence	$	193,475
Liabilities subject to compromise paid in cash or settled via equity share distribution:
Accrued interest on the Notes (equity shares)	$	7,285
10% senior unsecured notes due 2017 (equity shares)	141,000
Class 6 General Unsecured Claims (equity shares)	22,133
Class 7 Convenience Claims (paid or accrued for payment)	701
Liabilities subject to compromise paid in cash or settled via equity share distribution	$	171,119
Unamortized issuance costs of 10% senior unsecured note	$	(5,804	)
Total disposition of liabilities subject to compromise	$	358,790

(10)  Due to the payment of priority and secured claims and cure amounts in accordance with the Plan, the Company recorded a $28.5 million reduction in other long-term liabilities under Plan effects as follows:

Changes in Other long-term liabilities:
Partial settlement of the Kiewit Aurora West secured claim	$	10,000
Payment in full of Kiewit Mt. Vernon secured claim	7,931
Issuance of a short-term Kiewit Note as partial settlement of the Kiewit Aurora West secured claim	5,252
Payment of collateral for public utility Mt. Vernon lien	1,894
Reclassification of unpaid priority, secured, and cure amounts to accounts payable	1,582
Payment of employee-related priority administrative claims	937
Payment of cure amounts for assumed contracts	420
Payments of other secured claims	333
Payment of other priority administrative claims payments	196
Total	$	28,545

(11)  Plan effect adjustments to the Company’s statement of stockholder’s equity include the following:

·Gain due to plan effects in the two months ended February 28, 2010, of $136.6 million related to implementation of the Plan consisted of $193.5 million of liabilities subject to compromise

F-15

which were discharged upon emergence less $5.8 million of unamortized debt issuance costs on the 10% senior unsecured notes, $1.6 million related to the write-off of predecessor prepaid directors and officer insurance, $5.3 million of successor-based professional fees awarded under the Plan, $42.6 million related to loss on shares granted in connection with the Notes and $1.6 million of other miscellaneous costs.

·Elimination of predecessor equity balances comprised of:

·common stock of $44 thousand,

·additional paid-in capital of $294.7 million

·Issuance of successor common stock comprised of:

·common stock of $7 thousand

·additional paid-in capital of $219.9 million

·Adjustments to retained earnings of $426.3 million resulting from the net impact of all other plan effects, including the gain.

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

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

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

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

Property, plant and equipment—Property, plant and equipment was valued at fair value of approximately $208.8 million as of February 28, 2010. The Company’s management determined fair value. In establishing fair value for the vast majority of the Company’s property, plant and equipment, the cost approach was utilized. The cost approach considers the amount required to replace an asset by

F-16

constructing or purchasing a new asset with similar utility, then adjusts the value in consideration of all forms of depreciation as of the appraisal date as described below:

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

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

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

The cost approach relies on management’s assumptions regarding current material and labor costs required to rebuild and repurchase significant components of the Company’s property, plant and equipment along with assumptions regarding the age and estimated useful lives of its property, plant and equipment. After recording other assets and liabilities at their respective fair values, the balance of the enterprise value is allocated to the various classes of property, plant and equipment based on the appraisal as adjusted for the factors indicated above, which resulted in a write-down of property, plant and equipment of approximately $380.0 million. Factors contributing to the significant write-off of property, plant and equipment included:

·Uncompleted facilities are less marketable than operational facilities and were selling at a substantial discount to completed facilities;

·The plants require material capital contributions prior to experiencing any potential profits from production, and it was uncertain that the facilities would be completed if the Company did not have sufficient capital to fund completion.  There was also uncertainty as to whether the costs to complete the plants could be materially greater than estimated by management; and

·There were significant start-up risks because both plants under construction had sat idle through an entire winter and were expected to sit idle through the 2010 winter which could result in issues causing the equipment to fail to operate effectively.

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

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

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

F-17

All fresh start adjustments noted above represent non-recurring fair value measurements and have been treated as non-cash adjustments in the consolidated statement of cash flows.

(13)     Adjustments required in order to report assets and liabilities at fair value under fresh start accounting resulted in a pre-tax charge of $387.7 million, which the Company reported as a loss due to fresh start accounting adjustments in the consolidated statement of operations for the two months ending February 28, 2010.

In addition, the Company eliminated the balance of accumulated other comprehensive gains (net of losses) totaling $2.4 million, which were classified as a loss within reorganization items in the consolidated statement of operations for the two months ending February 28, 2010.

3.Summary of Significant Accounting Policies

The accounting policies below relate to amounts reported in the Company’s consolidated financial statements.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates are based on management’s knowledge of current events and actions that the Company may take in the future. Estimates, by their nature, are based on judgment and available information. Therefore, actual results could differ from those estimates and could have a material impact on the consolidated financial statements.

Revenue Recognition

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

The majority of sales are based upon freight costs being paid by the Company.  The Company recognizes such freight costs in the financial statements.  In other cases, freight costs are paid by the buyer and the Company excludes these costs from its financial statements.

Environmental Expenditures

Environmental expenditures that pertain to current operations and relate to future revenue are expensed or capitalized consistent with the Company’s 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.

F-18

Net Income (Loss) Per Share

In accordance with ASC 260, “Earnings Per Share” (“ASC 260”), the Company uses the two-class method to compute basic and diluted earnings per share.  ASC 260 addresses whether instruments granted in share-based payment awards that entitle their holders to receive non-forfeitable dividends or dividend equivalents before vesting should be considered participating securities and need to be included in the earnings allocation in computing net income (loss) per share under the “two-class method.” The two-class method is an earnings allocation formula that determines net income (loss) per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. In accordance with the standard, the Company’s restricted stock awards and restricted stock units are considered participating securities because they entitle holders to receive non-forfeitable dividends during the vesting term. In applying the two-class method, undistributed earnings are allocated between common shares, restricted stock awards and restricted stock units.

Fair Value Measurement

The Company accounts for certain financial assets and liabilities under ASC 820, Fair Value Measurements and Disclosures (“ASC 820”).  The Company uses the following methods in estimating fair value disclosures for financial instruments:

Cash and equivalents, 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 the Company’s borrowings under its revolving credit facility and the term loan approximates fair value. The fair value of the Notes at December 31, 2010, is based upon quoted closing market prices at year-end.

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

Available for sale securities: Available for sale securities consists of a common stock investment in an exchange traded security.  The fair value of these securities is determined using quoted market prices.

See Note 5 for additional information regarding the Company’s fair value assets and liabilities.

Cash and Cash Equivalents

The Company considers 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.

Accounts Receivable

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.

F-19

The allowance for doubtful accounts, bad debt provision and write-offs were as follows:

	Balance at Beginning of Period		Charged to Expense		Deductions			Balance at End of Period
	(In thousands)
For the Year Ended December 31, 2011 (Successor)
Allowance for doubtful accounts	$	75	$	220	$	(121	)	$	174
For the Ten Months Ended December 31, 2010 (Successor)
Allowance for doubtful accounts	$	—	$	75	$	—		$	75
For the Two Months Ended February 28, 2010 (Predecessor)
Allowance for doubtful accounts	$	2,400	$	1,601	$	(4,001	)	$	—
For the Year Ended December 31, 2009 (Predecessor)
Allowance for doubtful accounts	$	272	$	2,171	$	(43	)	$	2,400

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 bushels of corn purchased, gallons of ethanol produced at the Company’s plants, and other gallons purchased for resale, when applicable.  Inventory costs include expenditures incurred bringing inventory to its existing condition and location. Inventories primarily consist of agricultural and energy-related commodities, including corn, ethanol, and coal, and were as follows at December 31:

	December 31,
	2011		2010
	(In thousands)
Finished products	$	27,946	$	27,984
Work-in-process	6,542		6,008
Raw materials	8,809		10,187
Totals	$	43,297	$	44,179

Derivatives and Hedging Activities

Derivatives are accounted for in accordance with ASC 815, Derivatives and Hedging (“ASC 815”), and primarily consist of commodity futures contracts, swaps and option contracts.

The Company’s futures contracts were not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income.  Such derivative instruments are recorded at fair value, and are included in “Prepaid expenses and other current assets” on the Company’s consolidated balance sheets.  See Note 7.

Under ASC 815, companies are required to evaluate contracts to determine whether such contracts are derivatives.  Certain contracts that meet the definition of a derivative under ASC 815 may be exempted from the accounting and reporting requirements of ASC 815 as normal purchases or normal sales. The Company has elected to designate its forward purchases of corn and natural gas and forward sales of ethanol as normal purchases and normal sales under ASC 815.  Accordingly, these contracts are not reflected in the consolidated financial statements until execution.

F-20

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 basis 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.  See Note 8.

Impairment of Long-Lived Assets

Long-lived assets are evaluated for impairment under the provisions of ASC 360, Property, Plant and Equipment.  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.

Restricted Cash

There is no restricted cash at December 31, 2011.  Current restricted cash at December 31, 2010, represented cash held to redeem the $155.0 million Notes (see Note 11).  Noncurrent restricted cash represents cash held in segregated bank accounts of the Company, which is set aside as collateral to fund certain letters of credit and utility deposits.

Available for sale securities

Available for sale securities at December 31, 2011, consisted of shares of Imperial Petroleum Inc. (“Imperial”).  In December 2011, the Company recognized a non-cash loss on available-for-sale securities of $0.5 million due to the declining market value of the Imperial stock which was determined to be other than temporary.  In October 2010, the Company sold all of its available for sale securities consisting of Great Plains Renewable Energy (“GPRE”) stock and recognized a loss of approximately $2.0 million in “Loss on available-for-sale securities” on the consolidated statement of operations for the ten months ended December 31, 2010. See Note 6.

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.

The Company determines its actuarial assumptions for the pension and post retirement plans, after consultation with its 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 the projected returns for the investment mix and is determined 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

F-21

performance of the market in general and the historical performance of the retirement plan assets over the past ten years.

Employee Stock Plans

The Company accounts for its employee stock compensation in accordance with ASC 718, Compensation — Stock Compensation (“ASC 718”).  Stock options are expensed based on their grant date fair value. As required under the guidance, an accounting estimate of the number of shares that are expected to vest is made and then expensed utilizing the grant-date fair value of the shares from the date of grant through the end of the performance cycle period.  See Note 19.

Income Taxes

Deferred tax liabilities and assets are recorded for the expected future tax consequences of events that have been recognized in the financial statements or tax returns.  Property, plant and equipment, stock-based compensation expense, debt issuance costs and original issue discount are the primary sources of these temporary differences. Deferred income taxes also include net operating loss and capital loss carryforwards.  The Company establishes valuation allowances to reduce deferred tax assets to amounts it believes are realizable.  These valuation allowances and contingency reserves are adjusted based upon changing facts and circumstances. See Note 17.

Concentrations

Labor Concentration

Approximately 45% of the Company’s full-time employees at December 31, 2011 (comprised of the hourly employees at the Illinois facilities), are covered by a collective bargaining agreement between Aventine’s subsidiary, Aventine Renewable Energy, Inc., and the United Steelworkers International Union, Local 7-662 (the “Union”).   On October 29, 2010, the Union ratified a new collective bargaining agreement with Aventine Renewable Energy, Inc. for its hourly production workers in Pekin, Illinois. This new agreement is effective November 1, 2010, and runs through October 31, 2012. The agreement contains provisions, terms and conditions that are customary in collective bargaining agreements of this type, including, among other things, wages, hours, work assignments, management rights, seniority, arbitration and grievance procedures, benefits, vacations and holidays. The benefit and base wage packages for the currently covered employees remain substantially similar to those in the previous collective bargaining agreement; the currently covered employees received lump sum annual payments of $750 in November 2010 and November 2011. Employees hired after November 1, 2010, will only be eligible for the 401(k) program as their retirement benefit. The collective bargaining agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse affect on the Company’s business, financial condition and results of operations. There is no certainty that the current collective bargaining agreement will be extended or that a new collective bargaining agreement will be reached.

Concentration of Credit Risk

The Company sells ethanol to most of the major integrated oil companies, as well as a significant number of large, independent refiners and petroleum wholesalers.  Trade receivables result primarily from 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 accounts receivable resulted from the Company’s top 10 customers having generated 65.6% and 61.7% of the consolidated net sales for the years ended December 31, 2011 and 2010, respectively.

In 2011, Marathon Petroleum Corporation and Buckeye Energy Services, LLC (“Buckeye”)

F-22

accounted for 24.0% and 14.2%, respectively, of the Company’s consolidated net sales. In 2010, Buckeye and BioUrja Trading, LLC (“BioUrja”) accounted for 17.0% and 11.0%, respectively, of the Company’s consolidated net sales.   No other customers in 2011 or 2010 represented more than 10% of Aventine’s consolidated net sales.

Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”), which changes the presentation requirements of comprehensive income to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income.  ASU 2011-05 requires that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU 2011-05 is effective for interim and annual periods beginning after December 15, 2011.  The Company does not anticipate that the adoption of ASU 2011-05 will have a material impact on its consolidated financial statements.

In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”) (“ASU 2011-04”), which changes certain fair value measurement and disclosure requirements, clarifies the application of existing fair value measurement and disclosure requirements and provides consistency to ensure that GAAP and IFRS fair value measurement and disclosure requirements are described in the same way.  ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011.  The Company does not anticipate that the adoption of ASU 2011-04 will have a material impact on its consolidated financial statements.

4.Net Loss Per Share

Basic loss per share excludes any dilution and is computed by dividing net loss attributable to common shareholders by the weighted average number of common shares outstanding for the period. Diluted loss per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the entity. The dilution from each of these instruments is calculated using the treasury stock method. Outstanding equity instruments that could potentially dilute basic loss per share in the future but were not included in the computation of diluted loss per share because they were antidilutive are as follows:

	Successor		Predecessor
	For the Year Ended December 31,	For the Ten Months Ended December 31,	For the Two Months Ended February 28,	For the Year Ended December 31,
	2011	2010	2010	2009
	(In thousands)
Stock options	252	108	2,585	2,584
Restricted stock units	191	173	—	—
Totals	443	281	2,585	2,584

The Company used the two-class method to compute basic and diluted loss per share for all periods presented. The reconciliation of the net loss, net loss attributable to common shareholders and the weighted average number of share and share equivalents used in the computations of basic and diluted loss per share for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009 are as follows:

F-23

	Successor						Predecessor
	For the Year Ended December 31,			For the Ten Months Ended December 31,			For the Two Months Ended February 28,			For the Year Ended December 31,
	2011			2010			2010			2009
	(In thousands, except per share data)
Net loss attributable to common shareholders	$	(43,390	)	$	(25,464	)	$	(266,293	)	$	(46,260	)
Weighted average shares and share equivalents outstanding:
Basic and diluted shares	9,047			8,584			43,401			42,968
Loss per common share — basic and diluted	$	(4.80	)	$	(2.97	)	$	(6.14	)	$	(1.08	)

For the year ended December 31, 2011, 0.4 million shares contemplated by the Plan to be distributed to holders of allowed general, unsecured claims are included in the calculation of basic loss per share. See Note 19.

5.Fair Value Measurements

In accordance with ASC 820, the Company categorizes its investments and certain other assets and liabilities recorded at fair value into a three-level fair value hierarchy as follows:

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

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

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

Fair Value Hierarchy on a Recurring Basis

The following tables summarize the valuation of the Company’s financial instruments which are carried at fair value as of December 31, 2011 and 2010:

	Fair Value Measurements at December 31, 2011
	Fair Value		Quoted Prices in Active Markets Using Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In thousands)
Cash and cash equivalents	$	36,105	$	36,105	$	—	$	—
Derivative contracts	$	239	$	239	$	—	$	—
Available for Sale Securities	$	191	$	191	$	—	$	—
Renewable Identification Numbers	$	22	$	22	$	—	$	—

F-24

	Fair Value Measurements at December 31, 2010
	Fair Value		Quoted Prices in Active Markets Using Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In thousands)
Cash and cash equivalents	$	34,533	$	34,533	$	—	$	—
Derivative contracts	$	1,081	$	1,081	$	—	$	—

The Company did not hold any financial assets requiring the use of Level 2 or Level 3 inputs at December 31, 2011 and 2010.

Available for sale securities

The Company’s available for sale securities consists of shares of Imperial stock. The Company records the fair value of its Imperial stock using unadjusted quoted market prices, and accordingly, discloses these investments in Level 1 of the fair value hierarchy.

Realized gains (losses)

The Company recorded a net loss of $4.4 million on derivative transactions for the year ended December 31, 2011, and net gains of $0.6 million, $0.0 million and $1.2 million, respectively, for the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, in “Gain (loss) on derivative transactions, net” on the consolidated statements of operations.

Financial instruments not reported at fair value

The carrying value of other financial instruments, including restricted cash, accounts receivable and accounts payable and accrued liabilities approximate fair value due to their short maturities or variable-rate nature of the respective balances.  The following table presents the other financial instruments that are not carried at fair value, but which require fair value disclosure as of December 31, 2011 and 2010.

	December 31, 2011						December 31, 2010
	Carrying Value			Fair Value			Carrying Value			Fair Value
	(In thousands)
Term loan	$	(222,813	)	$	(222,813	)	$	(200,000	)	$	(200,000	)
Notes	$	—		$	—		$	(155,000	)	$	—

The term loan is at a variable rate and therefore the carrying value approximates the fair value.  The fair value of the Notes approximates fair value at December 31, 2010, based on notification of redemption on December 22, 2010. The Notes outstanding at December 31, 2010, were redeemed on January 21, 2011, at 105% of their carrying value.  The fair value of the term loan and notes was determined based on Level 2 factors.

6.Investments

Available for sale securities

Cumulative losses of $0.5 million were presented in “Other non-operating income” on the consolidated statements of operations for the year ended December 31, 2011.  At each reporting date, the Company performs an evaluation of impaired equity securities to determine if any unrealized losses are

F-25

other-than-temporary.  Such evaluation consists of a number of factors including, but not limited to, the length of time and extent to which the fair value has been less than cost, the financial condition and near term prospects of the issuer and management’s ability and intent to hold the securities until fair value recovers.  The assessment of the ability and intent to hold these securities to recovery focuses on liquidity needs, asset/liability management objectives and security portfolio objectives.  Based on the results of the evaluation, management concluded that as of December 31, 2011, the unrealized losses related to its 425,000 shares of Imperial were not temporary.

The Company previously held GPRE stock as available-for-sale securities.  In October 2010, the Company sold all of its GPRE securities for $4.2 million after commissions, resulting in a realized loss in the statement of operations for the ten months ended December 31, 2010, of approximately $2.0 million.

Investments in Marketing Alliances

The Company had previously made non-controlling investments in other ethanol producers, which were recorded on the cost basis.  All such investments were sold during 2009 with a recognized gain of $1.0 million.

7.Derivative Instruments and Hedging

The Company’s operations and cash flows are subject to fluctuations due to changes in commodity prices.  As such, the Company has historically used various derivative financial instruments to minimize the effects of the volatility of commodity price changes primarily related to corn, natural gas, and ethanol.  The Company monitors and manages its exposure as part of its overall risk management policy.  As such, the Company seeks to reduce the potentially adverse effects that the volatility of these markets may have on its operating results. The Company may take derivative positions in these commodities as one way to mitigate risk.

The Company is subject to market risk with respect to the price and availability of corn, the principal raw material it uses 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 the Company to pass along increased corn costs to its 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.  From time to time, the Company may have firm-price purchase commitments with some of its corn suppliers under which the Company agrees to buy corn at a price set in advance of the actual delivery of that corn.  Under these arrangements, the Company assumes 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.  The Company accounts for these transactions as normal purchases under ASC 815, and accordingly, it does not mark these transactions to market.

The Company periodically enters into firm-price purchase commitments with some of its natural gas suppliers under which the Company agrees to buy natural gas at a price set in advance of the actual delivery of that natural gas.  Under these arrangements, the Company assumes the risk of a price decrease in the market price of natural gas between the time this price is fixed and the time the natural gas is delivered.  At December 31, 2011, the Company had purchased forward 527,000 MMBtu’s of natural gas at an average fixed price of $3.28 per MMBtu through January 2012.  At December 31, 2010, the Company had purchased forward 477,300 MMBtu’s of natural gas at an average fixed price of $4.30 per MMBtu through the first quarter of 2011.  The Company accounts for these transactions as normal purchases under ASC 815, and accordingly, it does not mark these transactions to market.

The Company is also subject to market risk with respect to ethanol pricing.  The Company’s ethanol

F-26

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.  The Company sometimes fixes the price at which it sells ethanol using fixed price physical delivery contracts.  The Company has elected to account for these transactions as normal sales transactions under ASC 815, and accordingly, it has not marked these transactions to market.

Derivative instruments not designated as hedging instruments under ASC 815 at December 31, 2011 and 2010 were as follows:

		December 31,
Type	Balance Sheet Classification	2011		2010
		(In thousands)
Corn future positions	Other current assets	$	8.2	$	1,081.0
Ethanol future positions	Other current assets	$	911.3	$	—

The realized and unrealized effect on the Company’s consolidated statement of operations for derivatives not designated as hedging instruments under ASC 815 for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, were as follows:

		Successor						Predecessor
		For the Year Ended			For the Ten Months Ended			For the Two Months Ended		For the Year Ended
		December 31,			December 31,			February 28,		December 31,
Future Positions	Classification	2011			2010			2010		2009
		(In thousands)
Corn	Gain on derivative transactions	$	(2,235	)	$	3,705		$	—	$	1,219
Ethanol	Gain on derivative transactions	$	(2,189	)	$	(3,072	)	$	—	$	—

8.Property, Plant and Equipment

Property, plant and equipment at December 31, 2011 and 2010 were as follows:

	December 31,
	2011			2010
	(In thousands)
Land and improvements	$	12,064		$	6,593
Building and improvements	11,161			12,408
Machinery and equipment	190,457			136,965
Storage tanks	21,712			7,811
Furniture and fixtures	570			521
Less accumulated depreciation	(30,495		)	(8,828		)
Totals	$	205,469		$	155,470
Construction-in-progress	90,130			140,819
Total property, plant and equipment, net	$	295,599		$	296,289

Depreciation expense for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, was $24.0 million, $8.9 million, $2.3 million, and $14.4 million, respectively, and was recorded in “Cost of goods sold” on the consolidated statements of operations.

F-27

Construction-In-Progress

At December 31, 2011, construction-in-progress includes $56.6 million related to the construction of the Aurora West plant, $23.0 million related to the Canton facility acquired in August 2010, and $9.8 million related to capitalized projects at the Illinois facility.

At December 31, 2010, construction-in-progress includes $50.2 million related to the construction of the Aurora West plant, $67.0 million related to the construction of the Mt. Vernon plant and $17.1 million related to the Canton facility acquired in August 2010.

9.Short-Term Borrowings

The Company had no short term borrowings at December 31, 2011 or 2010.

Senior Secured Revolving Credit Facility with PNC Bank

Pursuant to the Plan, on the Effective Date, the Company and its subsidiaries, as borrowers, entered into a Revolving Credit and Security Agreement (the “Revolving Credit Agreement”) with PNC Bank, National Association, as lender and as agent (“PNC”), providing for a $20 million revolving credit facility (the “Revolving Facility”).  On February 28, 2011, the Company amended the Revolving Facility which increased the maximum loan amount to $30.0 million.

On July 20, 2011, the Revolving Credit Agreement with PNC was terminated and replaced with a revolving credit facility (the “New Revolving Facility”) with Wells Fargo Capital Finance, LLC.

Revolving Credit Facility with Wells Fargo

On July 20, 2011, the Company and each of its subsidiaries, as co-borrowers (collectively, the “Borrowers”), entered into the New Revolving Facility with the lenders party thereto (the “Lenders”), and Wells Fargo Capital Finance LLC as Lender and as agent for the Lenders (in such capacity, “Wells Fargo”) (as amended, and as may be amended, supplemented or otherwise modified from time to time, the “New Revolving Facility Agreement”) with a $50.0 million commitment (the “Commitments”).  The New Revolving Facility has a borrowing base that is principally supported by accounts receivable and inventory.  The Company terminated the Revolving Credit Agreement with PNC and paid a $0.6 million early termination fee.  In addition, the Company expensed $39 thousand in related unamortized debt issuance costs.  Both items are included in debt extinguishment costs for the year ended December 31, 2011.  The Company capitalized $2.9 million in debt issuance costs for the year ended December 31, 2011, related to the New Revolving Facility Agreement.  These costs will be amortized using the straight-line method over the term of the New Revolving Facility Agreement.  The Company recognized $0.3 million of expense for the amortization of debt issuance costs related to the New Revolving Facility Agreement during the year ended December 31, 2011.

The loans under the New Revolving Facility will mature on the earlier of (a) July 20, 2015, and (b) the date that is six (6) months before the maturity date of the indebtedness under the Term Loan Agreement (as defined below) (or if the indebtedness under the Term Loan Agreement is fully refinanced or replaced, the maturity date of such refinanced or replaced indebtedness).  The New Revolving Facility has a borrowing base principally supported by the inventory and accounts receivable of the Borrowers.

The rights and obligations of the lenders under the Revolving Credit Agreement have been assigned from PNC to Wells Fargo under the New Revolving Facility Agreement.  The New Revolving Facility Agreement includes a grant of liens on substantially all of the assets of the Borrowers.  The security interests granted under the New Revolving Facility in the assets (including inventory and accounts

F-28

receivable) other than substantially all of Borrowers’ fixed assets will be first priority in nature, subject to customary exceptions, and the security interests in the collateral constituting substantially all of the Borrowers’ fixed assets will be second priority in nature, and subject to customary liens and the first priority lien on such assets under Aventine’s senior secured term loan credit agreement dated as of December 22, 2010 by and among Aventine, as borrower, Citibank, N.A., as administrative agent and collateral agent (in such capacity, the “Term Loan Agent”), the lenders party thereto and certain other persons (as amended, and as may be amended, supplemented or otherwise modified from time to time, the “Term Loan Agreement”).

Borrowings under the New Revolving Facility Agreement will bear interest at (i) the London Interbank Offered Rate (“LIBOR”) plus 3.0% to 3.5% or (ii) the alternate base rate plus 2.0% to 2.5%.  The applicable margin on loans under the New Revolving Facility will be re-determined on the first day of each fiscal quarter of Aventine by calculating the average amount that the Borrowers are entitled to borrow under the New Revolving Facility (after giving effect to any outstanding borrowings thereunder) as a proportion of the Commitments (as decreased by the amount of reductions in the Commitments pursuant to the New Revolving Facility).  The alternate base rate will be calculated based on the greater of (A) the Federal funds rate plus 1/2 of 1.0%, (B) the LIBOR rate (calculated based upon an interest period of three months and determined on a daily basis), plus 1.0% and (C) the rate of interest announced, from time to time, by Wells Fargo Bank, National Association, as its “prime rate”.

The New Revolving Facility Agreement requires mandatory prepayment of the obligations thereunder in the event that the amount of (i) outstanding revolving loans under the New Revolving Facility plus (ii) the aggregate undrawn amount of all outstanding letters of credit issued by certain Lenders exceeds the Borrowing Base (as defined in the New Revolving Facility Agreement).

The New Revolving Facility Agreement contains customary affirmative and negative covenants concerning the conduct of Aventine’s business operations, such as limitations on the incurrence of indebtedness, the granting of liens, maintenance of operations, mergers, consolidations and dispositions of assets, restricted payments and the payment of dividends, investments and transactions with affiliates.

The New Revolving Facility Agreement contains a financial covenant that will require Aventine to maintain minimum liquidity levels of $25.0 million in 2013 and thereafter.  The New Revolving Facility Agreement also includes customary events of default, including, but not limited to, failure to pay principal or interest, failure to pay or default under other material debt, misrepresentation or breach of warranty, violation of certain covenants, a change of control, the commencement of a bankruptcy proceeding, any of the Borrowers’ insolvency and the rendering of a judgment or judgments against any of the Borrowers’ in excess of a specified amount individually or in the aggregate.  Upon the occurrence of an event of default, Aventine’s obligations under the New Revolving Facility Agreement may be accelerated and all indebtedness thereunder would become immediately due and payable.

At December 31, 2011, the Company had no short term borrowings and letters of credit outstanding of $9.2 million, respectively, under the New Revolving Facility.

F-29

10.Other Current Liabilities

	December 31,
	2011		2010
	(In thousands)
Deferred revenue	$	8,628	$	8,149
Accrued property taxes	1,705		892
Accrued sales tax	10		12
Other accrued operating expenses	2,474		1,536
Reserve for uncertain tax positions (see Note 17)	—		—
Accrued interest on uncertain tax positions (see Note 17)	—		—
Total short-term borrowings	$	12,817	$	10,589

11.Long-Term Debt

The following table summarizes the Company’s outstanding debt at December 31:

	December 31,
	2011			2010
	(In thousands)
Senior secured term loan credit agreement due December 2015 (net of discount of $8,000)	$	216,138		$	192,043
Senior secured 13% notes due March 2015 (including unamortized premium of $689)	—			155,689
Other	196			225
	$	216,334		$	347,957
Less: current maturities of long-term debt	(2,283		)	(157,718		)
Less: reclassification to pre-petition liabilities subject to compromise	—			—
Total long-term debt, net	$	214,051		$	190,239

Senior Secured Term Loan Credit Agreement

On December 22, 2010, the Company entered into the Term Loan Agreement with the Term Loan Agent, the lenders party thereto, Citigroup Global Markets Inc. and Jefferies Finance LLC, as joint lead arrangers and joint book-runners, and Citibank, N.A. and Jefferies Finance LLC, as co-syndication agents. Under the Term Loan Agreement, the lenders provided to the Company an aggregate principal amount $200 million term loan facility (the “Term Loan Facility”).  The Term Loan Facility was issued net of original issue discount of $8.0 million.

Also on December 22, 2010, the Company gave notice of redemption pursuant to the indenture dated as of the Effective Date among the Company, each of the Company’s direct and indirect wholly-owned subsidiaries, as guarantors, and Wilmington Trust FSB, as trustee and collateral agent, providing that it would redeem all $155.0 million aggregate principal amount of Notes at a redemption price of 105% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. Concurrently with the closing of the Term Loan Agreement, the Company irrevocably deposited in trust with the trustee for the Notes, $164.8 million of the proceeds from the Term Loan Facility, funds sufficient to pay the redemption price for all $155.0 million aggregate principal amount of the Notes. Accordingly, the Notes and the restricted cash for payment of the Notes were included in current liabilities and current assets, respectively, in the condensed consolidated balance sheet at December 31, 2010. The Company redeemed such Notes on January 21, 2011.  In connection with the redemption, the Company paid $164.8 million, of which $155.0 million related to the principal amount of the Notes, $7.8 million related to a prepayment penalty on the Notes and $2.0 million related to interest on the Notes.

On April 7, 2011, the Company entered into an incremental amendment (the “Incremental Amendment”) with the Term Loan Agent and Macquarie Bank Limited, as lender (“Macquarie”), to the

F-30

Company’s Term Loan Agreement.  Pursuant to the Incremental Amendment, Macquarie loaned an aggregate principal amount equal to $25.0 million, before fees of $1.3 million in fees, to the Company.  The loan under the Incremental Amendment has substantially the same terms as the existing loans under the Term Loan Agreement, including seniority, ranking in right of payment and of security, maturity date, applicable margin and interest rate floor.  The Company continues to be subject to all other terms and restrictions contained in the original Term Loan Agreement.

Borrowings under the Term Loan Agreement bear interest at (i) LIBOR plus 8.5% per annum or (ii) the alternate base rate plus 7.5% per annum.  The LIBOR rate is subject to a 2% floor.  The alternate base rate will be calculated based on the greater of (i) 3% per annum and (ii) the highest of (A) the Federal funds rate plus 1/2 of 1%, (B) the LIBOR rate for an interest period of one month plus 1%, (C) the three-month certificate of deposit rate plus 1/2 of 1%, and (D) Citibank, N.A.’s prime rate.

On July 20, 2011, the Company entered into an amendment (“Citi Amendment”) to the Term Loan Agreement with the lenders party thereto and the Term Loan Agent.  Under the terms of the Citi Amendment, the amount of indebtedness that the Company is permitted to incur under the New Revolving Facility (including bank products and hedging obligations) is capped at $58.0 million. The Citi Amendment reduces the Company’s minimum liquidity covenant for 2012 from $25.0 million to $15.0 million. The Citi Amendment also includes certain technical amendments to permit the New Revolving Facility.

Debt Maturities

Maturities relating to outstanding debt, including interest, at December 31, 2011, for each of the five years in the period ending December 31, 2016, and thereafter are as follows:

	December 31, 2011
	(In thousands)
2012	$	25,613
2013	25,377
2014	25,140
2015	238,217
2016	37
Thereafter	—
Total	$	314,384

12.Interest Expense

The following table summarizes interest expense:

F-31

	Successor						Predecessor
	For the Year Ended December 31,			For the Ten Months Ended December 31,			For the Two Months Ended February 28,		For the Year Ended December 31,
	2011			2010			2010		2009
	(In thousands)
Interest expense:
Senior secured notes	$	1,119		$	13,211		$	—	$	—
Term loan facility	23,167			600			—		—
Senior unsecured notes	—			—			—		8,083
Revolving credit facility	61			288			600		2,464
Debtor-in-possession debt facility	—			—			502		1,785
Other	994			79			—		—
Amortization of deferred debt issuance costs	1,802			284			313		2,343
Amortization of original issue discount	1,281			—			—		—
Other	—			33			7		22
Capitalized interest	(4,238		)	(6,221		)	—		—
Interest expense, net	$	24,186		$	8,274		$	1,422	$	14,697

During the year ended December 31, 2011, and the ten months ended December 31, 2010, the Company recorded $2.1 and $3.6 million, respectively, of capitalized interest related to its capacity expansion project in Aurora, Nebraska, and $0.7 and $2.6 million, respectively, of capitalized interest related to its capacity expansion projects in Mt. Vernon, Indiana and $1.4 and $0.0 million of capitalized interest related to its capacity expansion in Canton, Illinois.  The Company did not capitalize any interest for the two months ended February 28, 2010.

13.Commitments and Contingencies

Lease Commitments

The Company leases 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. Rental expense for operating leases for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, was $6.8 million, $3.6 million, $0.6 million,  and $9.2 million, respectively.

The Company had capital lease obligations of $0.4 million at December 31, 2011, which were payable through 2013 at an assumed interest rate of 8.0%.  Such capital leases are recorded in “Other long-term liabilities” on the consolidated balance sheet.

At December 31, 2011, minimum rental commitments under non-cancelable lease terms in excess of one year are as follows:

	Minimum Rental Commitments
December 31,	Capital		Operating
	(In thousands)
2012	$	371	$	8,226
2013	30		6,696
2014	—		4,675
2015	—		4,072
2016	—		1,023
Thereafter	—		6,374
Total minimum lease payments	401		31,066
Less amount representing interest	20		—
Present value of capital lease commitments	$	381	$	31,066

F-32

Other Commitments

At December 31, 2011, the Company had forward contracts to purchase approximately 217,200 tons of coal for $17.1 million, delivered.

At December 31, 2011, the Company had committed to purchase approximately 527,000 MMBtus of natural gas for $1.7 million during 2012, delivered.

At December 31, 2011, the Company had firm-price purchase commitments to purchase approximately 1.2 million bushels of corn through February 2012 and future contracts to sell 45 thousand bushels of corn.  These commitments were negotiated in the normal course of business and represent a portion of our corn requirements.

Environmental Remediation and Contingencies

The Company is 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 the Company’s employees.  These laws, regulations, and permits require the Company to incur significant capital and other costs, including costs to obtain and maintain expensive pollution control equipment.  They may also require the Company 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. As such, the Company has not accrued any amounts for environmental matters as of December 31, 2011.

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

The Company has made, and expects to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the U.S. Environmental Protection Agency’s (“EPA”) National Emissions Standard for Hazardous Air Pollutants (“NESHAP”) for industrial, commercial and institutional boilers and process heaters (also known as “Boiler MACT”).  This NESHAP was issued but subsequently vacated in 2007.  The vacated version of the rule required the Company to implement maximum achievable control technology at its Illinois wet mill facility to reduce hazardous air pollutant emissions from its boilers.  The EPA issued a new Boiler MACT rule on March 21, 2011, but on May 18, 2011 it published a notice delaying the effective date of the new rule to allow the agency to reconsider its effect.  On December 2, 2011, the EPA released proposed amendments to the new Boiler MACT rule, and the public comment period closed on February 21, 2012.  The proposed rule is more stringent than the vacated version depending on boiler sizes, whether the source is new or existing, and it sets work practice standards for various emissions.  Significantly, on January 9, 2012, the District Court for the District of Columbia vacated the May 2011 action by the EPA,

F-33

which delayed the implementation of the new Boiler MACT.  The effect of the vacatur is that the revisions to the Boiler MACT became immediately effective.  Notwithstanding the vacatur, the EPA issued a “No Action Assurance Letter” to establish that it will exercise its enforcement discretion to not pursue enforcement action for violations of certain notification deadlines in the final Major Source Boiler MACT rule. The EPA intends to issue the final reconsideration rule prior to any of the compliance dates for existing sources.  In the absence of a final EPA NESHAP for industrial, commercial and institutional boilers and process heaters, the Company working with state authorities to determine what technology will be required at its Illinois wet mill facility and when such technology must be installed.  The Company currently cannot estimate the amount that will be needed to comply with federal or possible state technology requirement regarding air emissions from its boilers.

Litigation Matters

On November 6, 2008, the Company commenced an action against JP Morgan Securities, Inc. and JP Morgan Chase Bank, N.A. (hereinafter collectively referred to as ‘‘JP Morgan’’) in the Tenth Judicial Circuit in Tazewell County, Illinois. The Company’s complaint relates to losses incurred of approximately $31.6 million as a result of investments in Student Loan Auction Rate Securities purchased through JP Morgan.   This state court litigation is currently under a stay by the Circuit Court, which has prevented further prosecution of this dispute in that forum.  On June 10, 2011 the Company filed a request for arbitration with FINRA.  The request has been granted and the matter will move forward under FINRA Code of Arbitration Proceedings.    At this time, the Company is unable to determine the impact such litigation will have on our business, operating results, financial condition and cash flows.

On April 7, 2009, the Debtors filed voluntary petitions with the Bankruptcy Court to reorganize under Chapter 11 of the Bankruptcy Code.  The Plan was confirmed by order entered by the Bankruptcy Court on February 24, 2010, and became effective on March 15, 2010, the date on which the Company emerged from protection under Chapter 11 of the Bankruptcy Code.  Since March 15, 2010, certain of the Debtors’ cases have been closed by order of the Bankruptcy Court, effective December 20, 2010; however, the cases of Aventine Renewable Energy, Inc. and Nebraska Energy, L.L.C. remain open, wherein certain creditor claims remain subject to dispute and further adjudication, as do certain claims and potential claims by the Debtors against various third parties.  At this time, the Company is unable to determine the impact such litigation will have on its business, operating results, financial condition and cash flows.

On April 19, 2011, the Company was notified of the EPA’s intent to file an administrative complaint against Aventine Renewable Energy, Inc. for a release which occurred in March 2008.  The EPA noted that they would be seeking a penalty of approximately $0.2 million.  The Company has responded stating that its position is that such claims are barred by the bankruptcy proceedings.  At this time, the Company is unable to determine the impact such litigation will have on its business, operating results, financial condition and cash flows.

The Company initiated a civil action against E-Biofuels, LLC (“E-Biofuels”) in 2009 related to breach of agreement, and asked for not less than $3.0 million in compensation.  This suit was later transferred to the Bankruptcy Court and subsequently settled in the Company’s favor on July 6, 2011.  Under the terms of the settlement, the Company received $0.2 million in cash and 425,000 shares of Imperial (E-Biofuels’ parent company) stock.   The stock was valued at $0.7 million on the date of receipt of July 6, 2011.  The Company also had previously recorded a liability related to tax credits of $0.7 million which was relieved by the settlement.  The net gain of $1.6 million is included in other non-operating income for the year ended December 31, 2011, on the statement of operations.  The stock was booked as short-term investments which are classified as available for sale securities on the balance sheet.  For the year ended December 31, 2011, the Company booked a loss on available for sale securities of $0.5 million related to the decrease in the current trading price of the stock which is included in other non-operating income on the income statement.

F-34

On September 3, 2009, Union Tank Car Company (“Union Tank”) filed notice of a claim against the Company with the Bankruptcy Court for a general unsecured claim in the amount of $82.6 million for certain estimated end charges including railcar cleaning cost and unpaid rental payments for leased railcars.  Union Tank also filed an administrative claim against the Company in the amount of $0.1 million for the alleged use of railcars after the effective date of the rejection of the leases for such railcars.  The Company disputed both of these claims.  On September 30, 2011, the Court ruled that the claim shall be allowed in the amount of $27.6 million.  Partial distribution of shares on account was made October 31, 2011, in accordance with the terms of the Plan and at such time as the distribution was made to other holders of claims in classes five and six that were allowed as of September 30, 2011.  As a result of the settlement on September 30, 2011, the Company reversed the related reserve for this matter of $0.1 million through non-operating income on the statements of operations.

From time to time, the Company is involved in various legal proceedings, including legal proceedings relating to the extensive environmental laws and regulations that apply to the Company’s facilities and operations. The Company is not involved in any legal proceedings, other than those described herein, that it believes could have a material adverse effect upon the Company’s business, operating results, financial condition or cash flows.

14.Related Party Transactions

Pursuant to a Backstop Commitment Agreement, dated as of December 3, 2009, among the Company and Brigade Capital Management, LLC (“Brigade”), Nomura Corporate Research & Asset Management, Inc., Whitebox Advisors, LLC (“Whitebox”), Senator Investment Group LP (“Senator”) and SEACOR Capital Corporation (collectively, the “Backstop Purchasers”), the Backstop Purchasers committed to purchasing specified percentages of the Notes and 1,710,000 shares of the Company’s common stock issued and sold in the private placement that closed on March 15, 2010. Upon emergence from bankruptcy, the Backstop Purchasers received their respective percentages of the Notes and shares of the Company’s common stock (at a 3.0% discount to the $952.38 unit price), with Brigade receiving approximately 27.0% in aggregate principal amount of the Notes and shares of common stock sold in the offering and Senator receiving approximately 12.0% in aggregate principal amount of the Notes and shares of common stock sold in the offering.

Pursuant to the Plan and Confirmation Order, on March 15, 2010, the Company on the one hand, and Brigade, Whitebox and Senator (collectively, the “Majority Backstop Purchasers”) on the other hand, entered into a Registration Rights Agreement (the “Noteholder New Equity Registration Rights Agreement”) with respect to the shares of common stock that, on or following the Effective Date of the Company’s Plan, were issued to (i) holders of the pre-petition notes (the “Old Notes”) that were cancelled pursuant to the Plan that subscribed to the sale of the Notes and 1,710,000 shares of new common stock and (ii) the Backstop Purchasers or managed funds or accounts of the Backstop Purchasers. The Backstop Purchasers or their managed funds or accounts were holders of the Old Notes. The Noteholder New Equity Registration Rights Agreement requires the Company to file with the SEC a registration statement relating to the 1,710,000 shares of common stock and shares of common stock held by managed funds or accounts of the Backstop Purchasers no later than the 180th day following the Effective Date of the Company’s Plan and to cause such registration statement to be declared effective no later than the 365th day after the Effective Date of the Plan, in accordance with the terms and conditions set forth therein. The Noteholder New Equity Registration Rights Agreement also provides holders of general unsecured claims that receive 10% of the aggregate number of shares of common stock outstanding after all shares of common stock to be distributed under the Plan have been distributed with certain piggyback registration rights in connection with the registration of the 1,710,000 shares of common stock and shares of stock held by managed funds or accounts of the Backstop Purchasers. The Company filed a registration statement as required under the Noteholder New Equity Registration Rights Agreement. The company filed a registration statement with the SEC on September 10, 2010, which was within the Noteholder New Equity Registration Rights

F-35

Agreement specified period of 180 days following the effective date of our plan of reorganization.  However, as of the date of filing this Annual Report, the registration statement has not yet been declared effective.  Management believes that this will not have a financial impact to the Company.

On August 2, 2010, the Company and its subsidiaries entered into a commitment letter agreement with Brigade and Senator pursuant to which, subject to certain conditions, Brigade and Senator agreed to purchase up to an aggregate principal amount of $50 million of the Notes that were not purchased by other investors in a private placement offering on or after August 15, 2010, until September 15, 2010, at which time Brigade and Senator could have terminated the agreement if the offering had not been consummated on or before such date. In consideration for their agreement to backstop the private placement, the Company paid Brigade and Senator a commitment fee of $500,000 in the aggregate, which became payable on the closing of the offering on August 19, 2010. The Company also entered into a registration rights agreement with Brigade and Senator related to the exchange of its additional $50 million in principal amount of Notes for substantially similar notes registered under the Exchange Act. Two of the Company’s directors, Mr. Hawks and Mr. Silverman are employees of Brigade and Senator, respectively.

On August 6, 2010, the Company and New LIE Energy Opco, LLC, d/b/a Riverland Biofuels (“Riverland”) entered into an Asset Purchase Agreement (the “Purchase Agreement”) pursuant to which the Company acquired substantially all of the assets, and assumed specified liabilities, of Riverland for a purchase price of $16.5 million. The assets comprise the Canton facility, and include real property at the plant site, as well as surrounding parcels. Affiliates of Whitebox, whose affiliates hold over 10% of the Notes and common stock, also held a controlling interest in Riverland and guaranteed the repayment of a $5.0 million dollar deposit the Company made in June 2010 with respect to the facility. The acquisition closed on August 6, 2010. The Purchase Agreement includes customary representations, warranties and indemnification provisions.

On December 22, 2010, the Company entered into the Term Loan Agreement whereby the lenders provided us an aggregate principal amount $200.0 million Term Loan Facility. Subject to the satisfaction of certain conditions, the Company may request the creation of one or more new tranches of term loans or increase in the total commitments under the Term Loan Agreement in an amount up to $25.0 million. Two of the lenders under the Term Loan Agreement are Brigade and Senator.

15.Retirement and Pension Plans

Defined Contribution Plan

The Company has 401(k) plans covering substantially all of its employees. Contributions made under the defined contribution plans include a match, at the Company’s discretion, of an employee’s contribution to the plans.  For the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, such contributions amounted to $0.9 million, $0.6 million, $0.1 million, and $0.9 million, respectively.

Qualified Retirement Plan

The Company has a defined benefit pension plan (the “Retirement Plan”) that is noncontributory, and covers unionized employees at its 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.  On October 29, 2010, the Union ratified a new collective bargaining agreement with the Company for its hourly production workers in Pekin, Illinois.  This new agreement was effective November 1, 2010.  The agreement states that, among other things, employees hired after November 1, 2010, will not be eligible to participate in the Retirement Plan.  The Company uses a December 31 measurement date for its Retirement Plan.

F-36

Changes in the benefit obligations, the fair value of the assets, the funded status and amount recognized in the consolidated statements of financial condition were as follows:

	December 31,
	2011			2010
	(In thousands)
Changes in benefit obligation
Benefit obligation at the beginning of the year	$	10,405		$	9,281
Service cost	364			336
Interest cost	566			537
Actuarial loss	2,592			683
Benefits paid	(437		)	(432		)
Benefit obligation at the end of the year	$	13,490		$	10,405
Changes in plan assets
Fair value at the beginning of the year	$	10,308		$	8,839
Actual return on plan assets	116			1,148
Employer contributions	617			753
Benefits paid	(437		)	(432		)
Fair value of plan assets at the end of the year	$	10,604		$	10,308
Funded surplus (deficit) at the end of the year	$	(2,886	)	$	(97	)
Amounts recognized in the consolidated statements of financial condition:
Noncurrent liabilities	$	(2,886	)	$	(97	)
Amounts recognized in accumulated other comprehensive income (loss):
Net loss	$	3,376		$	94
Noncurrent liabilities	—			—
Amounts recognized	$	3,376		$	94

The fair value of plan assets, the accumulated benefit obligation and the projected benefit obligation were as follows:

F-37

	December 31,
	2011		2010
	(In thousands)
Fair value of plan assets	$	10,604	$	10,308
Accumulated benefit obligation	$	13,490	$	10,405
Projected benefit obligation	$	13,490	$	10,405

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

	Successor						Predecessor
	For the Year Ended December 31,			For the Ten Months Ended December 31,			For the Two Months Ended February 28,			For the Year Ended December 31,
	2011			2010			2010			2009
	(In thousands)
Components of net periodic benefit cost (credit):
Service cost	$	364		$	280		$	56		$	339
Interest cost	566			450			87			508
Expected return on plan assets	(805		)	(578		)	(115		)	(561		)
Amortization of net actuarial loss	—			—			14			178
Amortization of prior service cost	—			—			7			42
Net periodic pension cost	$	125		$	152		$	49		$	506
Actual return on plan assets	$	116		$	1,140		$	8		$	1,669
Employer contributions	$	617		$	671		$	82		$	246
Benefits paid	$	437		$	366		$	66		$	391
Other changes in plan assets and benefit obligations recognized in AOCI:
Net (gain)/loss	$	3,376		$	94		$	133		$	(1,089	)
Amortization of net (loss)/gain	—			—			(14		)	(178		)
Amortization of prior service (cost)/credit	—			—			(7		)	(42		)
Total recognized in AOCI	$	3,376		$	94		$	112		$	(1,309	)
Net amount recognized in total periodic benefit cost and AOCI	$	3,501		$	246		$	161		$	(803	)

The Company did not recognize any amortization of net actuarial losses for the year ended December 31, 2011, for the ten months ended December 31, 2010, or for the year ended December 31, 2009, as losses as of February 28, 2010, and January 1, 2009, respectively, did not exceed 10% of projected benefit obligation.

The Company is expected to contribute approximately $659 thousand in the year ending December 31, 2012.

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

F-38

	Successor				Predecessor
	For the Year Ended December 31,		For the Ten Months Ended December 31,		For the Two Months Ended February 28,		For the Year Ended December 31,
	2011		2010		2010		2009
	(In thousands)
Assumptions used to determine benefit obligation: Discount rate	4.30	%	5.41	%	5.88	%	5.87	%
Assumptions used to determine net periodic benefit cost:
Discount rate	5.41	%	5.88	%	5.87	%	6.00	%
Expected long-term rate of return on plan assets	7.75	%	7.75	%	7.75	%	7.75	%

The Company generated actuarial losses for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, primarily from the decrease in the discount rate used in the calculation of the benefit obligation to 5.41% at December 31, 2011, 5.88% at December 31, 2010 from 5.87% at February 28, 2010, and 6.00% at December 31, 2009.

Expected Benefit Payments—The following table summarizes the expected benefit payments for the Company’s plans for each of the next five fiscal years and in the aggregate for the five fiscal years thereafter:

	December 31, 2011
	(In thousands)
2012	$	463
2013	$	485
2014	$	510
2015	$	528
2016	$	580
2017 - 2021	$	3,245

Plan Assets

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 49% equities and 51% debt.  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.

Plan assets are invested using a total return investment approach whereby a mix of equity securities and debt securities are used to preserve asset values, diversify risk and achieve the Company’s target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan’s funded status and the Company’s financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.

Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of fund assets, while the role of fixed income investments is to generate current

F-39

income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of fund equity investments.

Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds.

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

	Successor				Predecessor
	December 31,
	2011		2010		2009
Equity securities	49	%	50	%	54	%
Debt securities	51	%	50	%	46	%
Total	100	%	100	%	100	%

The following table presents the categorization of plan assets, measured at fair value as of December 31, 2011:

Asset Category	Market Value at 12/31/11		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Large Cap U.S. Equity Securities (1)	$	3,147	$	—	$	3,147	$	—
Small/Mid Cap U.S. Equity Securities (2)	$	905	$	—	$	905	$	—
International Equity Securities (3)	$	1,145	$	—	$	1,145	$	—
Debt Securities (5)	$	5,407	$	—	$	5,407	$	—
Total Pension Assets	$	10,604	$	—	$	10,604	$	—

The following table presents the categorization of plan assets, measured at fair value as of December 31, 2010:

Asset Category	Market Value at 12/31/10		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Large Cap U.S. Equity Securities (1)	$	3,016	$	—	$	3,016	$	—
Small/Mid Cap U.S. Equity Securities (2)	$	735	$	—	$	735	$	—
International Equity Securities (3)	$	162	$	—	$	162	$	—
Real Estate Mutual Fund (4)	$	1,261	$	—	$	1,261	$	—
Debt Securities (5)	$	5,134	$	—	$	5,134	$	—
Total Pension Assets	$	10,308	$	—	$	10,308	$	—

(1)This category includes investments in funds comprised of equity securities of large U.S. companies.  The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

F-40

(2)This category includes investments in funds comprised of equity securities of small and medium sized U.S. companies.  The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(3)This category includes investments in funds comprised of equity securities of foreign companies including emerging markets.  The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(4)This category includes investments in funds comprised of a single mutual fund which invests in real estate.  The funds are valued using a publicly quoted market price of the mutual fund, although the value of the separate account is not publicly available.

(5)This category includes investments in funds comprised of U.S. and foreign investment grade fixed income securities, high yield fixed income securities that are rated below investment grade, U.S. treasury securities, mortgage backed securities and other asset backed securities.  The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

16.Postretirement Benefit Obligation

The Company sponsors a health care plan and life insurance plan (“Postretirement Plan”) that provides postretirement medical benefits and life insurance to certain “grandfathered” unionized employees.  Employees hired after December 31, 2000, are not eligible to participate in the Postretirement Plan. The plan is contributory, with contributions required at the same rate as active employees.  Benefit eligibility under the plan reduces at age 65 from a defined benefit to a defined dollar cap based upon years of service.

On December 31, 2011, the annual measurement date, the Postretirement Plan had an accumulated benefit obligation of $3.1 million, which is greater than the accumulated benefit obligation at December 31, 2010, of $2.2 million.  The Postretirement Plan is unfunded and has no assets.

Changes in the benefit obligations, the fair value of the assets, the funded status and amount recognized in the consolidated statements of financial condition were as follows:

F-41

	December 31,
	2011			2010
	(In thousands)
Changes in benefit obligation
Benefit obligation at the beginning of the year	$	2,206		$	2,023
Service cost	94			67
Interest cost	127			115
Actuarial loss	696			38
Benefits paid	(37		)	(37		)
Benefit obligation at the end of the year	$	3,086		$	2,206
Changes in plan assets
Fair value at the beginning of the year	$	—		$	—
Employer contributions	37			37
Benefits paid	(37		)	(37		)
Fair value of plan assets at the end of the year	$	—		$	—
Funded surplus (deficit) at the end of the year	$	(3,086	)	$	(2,206	)
Amounts recognized in the consolidated statements of financial condition:
Current liabilities	(49		)	(34		)
Noncurrent liabilities	(3,037		)	(2,172		)
Amounts recognized	$	(3,086	)	$	(2,206	)
Amounts recognized in accumulated other comprehensive income (loss):
Net (gain)/loss	$	841		$	152

A summary of the components of net periodic postretirement cost for the Postretirement Plan for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, is as follows:

	Successor					Predecessor
	For the Year Ended December 31,			For the Ten Months Ended December 31,		For the Two Months Ended February 28,			For the Year Ended December 31,
	2011			2010		2010			2009
	(In thousands)
Components of net postretirement benefit cost (credit):
Service cost	$	93		$	54	$	12		$	76
Interest cost	127			95		20			111
Amortization of net actuarial loss	7			—		(4		)	(37		)
Net postretirement pension cost	$	227		$	149	$	28		$	150
Other changes in benefit obligations recognized in accumulated other comprehensive income (loss):
Net loss/(gain)	$	697		$	152	$	(113	)	$	6
Amortization of net loss	(7		)	—		3			36
Total recognized in accumulated other comprehensive loss	$	690		$	152	$	(110	)	$	42
Net amount recognized in post-retirement benefit cost and accumulated other comprehensive loss	$	917		$	301	$	(82	)	$	192

Items not yet recognized as a component of net periodic postretirement cost and recognized in the consolidated balance sheets are as follows at December 31:

F-42

	December 31,
	2011			2010
	(In thousands)
Unfunded status	$	(3,086	)	$	(2,206	)
Amounts recognized in:
Current liabilities	$	(49	)	$	(34	)
Long-term liabilities	$	(3,037	)	$	(2,172	)
Deferred taxes	$	—		$	—
Accumulated other comprehensive loss:
Unamortized net actuarial loss (gain)	$	841		$	152

The Company does not expect to recognize amortization of net actuarial loss in 2012.

The weighted-average discount rate used to determine net periodic postretirement benefit cost was 4.2% for the year ended December 31, 2011, 5.4% for the ten months ended December 31, 2010, 5.9% for the two months ended February 28, 2010, and 6.0% for the year ended December 31, 2009.

Expected Benefit Payments— The following table summarizes the expected benefit payments for the Company’s plan for each of the next five fiscal years and in the aggregate for the five fiscal years and thereafter:

	December 31, 2011
	(In thousands)
2012	$	50
2013	$	86
2014	$	114
2015	$	80
2016	$	126
2017 - 2021	$	827

For purposes of determining the cost and obligation for pre-Medicare postretirement medical benefits, a 7.5% annual rate of increase in the per capita cost of covered benefits (i.e., health care trend rate) was assumed for the plan in 2011, declining to a rate of 5.7% in 2020.  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:

	1% Increase				1% Decrease
	2011		2010		2011			2010
	(In thousands)
Effect on total of service and interest cost components	$	21	$	14	$	(18	)	$	(12	)
Effect on postretirement benefit obligation	$	247	$	176	$	(216	)	$	(154	)

Patient Protection and Affordable Care Act

In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) was enacted, potentially impacting the Company’s cost to provide healthcare benefits to its eligible active and retired employees.  The PPACA has both short-term and long-term implications on benefit plan standards.  Implementation of this legislation is planned to occur in phases, beginning in 2010, and extending through 2018.

F-43

17.Income Taxes

The provision for income taxes for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, consists of the following:

	Successor					Predecessor
	For the Year Ended December 31,		For the Ten Months Ended December 31,			For the Two Months Ended February 28,			For the Year Ended December 31,
	2011		2010			2010			2009
	(In thousands)
Current expense (benefit)	$	484	$	881		$	(626	)	$	(6,193	)
Deferred expense (benefit)	52		(910		)	—			(2,845		)
Interest income (expense)	—		—			—			82
Total income tax expense (benefit)	$	536	$	(29	)	$	(626	)	$	(8,956	)

Reconciliation of differences between the statutory U.S. federal income tax rate and the effective tax rate follows for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009:

	Successor										Predecessor
	For the Year Ended December 31,					For the TenMonths Ended December 31,					For the Two Months Ended February 28,					For the Year Ended December 31,
	2011					2010					2010					2009
	(In thousands, except percentages)
Income tax provision (benefit) at federal statutory rate	$	(14,999	)	35.0	%	$	(8,922	)	35.0	%	$	(93,422	)	35.0	%	$	(19,325	)	35.0	%
Increase/(decrease) in taxes resulting from:
State and local taxes, net of federal benefit	(1,659		)	3.9		(1,020		)	4.0		(10,677		)	4.0		(2,079		)	3.7
Recognition of previously unrecognized uncertain tax positions	—			—		—			—		—			—		142			(0.2	)
Goodwill	—			—		—			—		—			—		(678		)	1.2
Change in deferred rate	(5,221		)	12.1		—			—		—			—		—			—
Increase (decrease) in valuation allowances	5,905			(13.8	)	23,057			(90.4	)	140,351			(52.6	)	10,064			(18.2	)
Deferred tax adjustments	16,380			(38.2	)	(14,133		)	55.4		(21		)	0.0		—			—
Non-deductible reorganization expense	—			—		—			—		—			—		1,869			(3.4	)
Indemnification proceeds	—			—		—			—		—			—		—			—
Domestic permanent difference	130			(0.3	)	719			(2.8	)	(36,857		)	13.8		—			—
Other	—			—		270			(1.1	)	—			—		1,051			(1.9	)
Income tax expense/(benefit)	$	536		(1.3	)%	$	(29	)	0.1	%	$	(626	)	0.2	%	$	(8,956	)	16.2	%

Deferred income taxes included in the 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.

F-44

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

	December 31,
	2011			2010
	(In thousands)
Current deferred tax asset	$	4,979		$	6,115
Valuation allowance	(4,837		)	(5,927		)
Net current deferred tax asset	$	142		$	188
Current deferred tax liability	$	1,287		$	1,516
Long-term deferred tax liabilities:
Partnership investment	$	6,432		$	6,414
Benefit obligations	—			—
Unrealized gain on bankruptcy	197			194
Basis of property, plant and equipment	—			—
Accumulated other comprehensive income	—			—
Other	—			—
Long-term deferred tax liability	$	6,629		$	6,608
Long-term deferred tax assets:
Basis of property, plant and equipment	$	130,744		$	150,410
Debt issuance costs and original issue discount	24			30,325
Capital losses	6,665			3,763
State NOLs	8,660			2,977
Federal NOLs	46,729			—
Stock-based compensation	3,449			2,828
Benefit obligations	2,305			762
Investment in marketing alliances	696			689
Unrealized loss on bankruptcy	—			—
Valuation allowance	(193,576		)	(185,844		)
Long-term deferred tax assets	$	5,696		$	5,910
Net deferred tax asset (liability)	$	(2,078	)	$	(2,026	)

The deferred tax provision at December 31, 2011, December 31, 2010, February 28, 2010, and December 31, 2009, does not reflect the tax effect of $1.7 million, $0.1 million, $0.0 million, and $0.5 million, respectively, resulting from the pension and other postretirement liability components included in accumulated other comprehensive income.

At December 31, 2011 and 2010, the Company has recorded valuation allowances of $198.4 million and $191.7 million, respectively, on its deferred tax assets to reduce the deferred tax assets to the amount that management believes is more likely than not to be realized.  Management considered the scheduled reversal of deferred tax liabilities and tax planning strategies in making this assessment.  The deferred tax assets subject to the valuation allowance primarily include tax benefits associated with capital loss on securities, stock-based compensation, basis of property, plant and equipment, benefit obligations, debt issuance costs and original issuance discount and both federal and state income tax net operating loss carryforwards.

F-45

Valuation allowances on deferred tax accounts deducted from the respective deferred tax assets are as follows:

	Balance at Beginning of Period		Charged to Cost and Expenses		Charged to Other Accounts			Deductions		Balance at End of Period
	(In thousands)
For the Year Ended December 31, 2011 (Successor)
Deferred tax valuation	$	191,771	$	5,905	$	737		$	—	$	198,413
For the Ten Months Ended December 31, 2010 (Successor)
Deferred tax valuation	$	166,460	$	23,057	$	2,254		$	—	$	191,771
For the Two Months Ended February 28, 2010 (Predecessor)
Deferred tax valuation	$	26,406	$	140,351	$	(297	)	$	—	$	166,460
For the Year Ended December 31, 2009 (Predecessor)
Deferred tax valuation	$	17,345	$	10,064	$	(1,003	)	$	—	$	26,406

At December 31, 2011 and 2010, the Company had deferred state tax benefits of $8.7 and $3.0 million, respectively, relating to state net operating loss carryforwards, which are available to offset future state taxable income through 2032.  Due to uncertainties regarding realization of the tax benefits, a valuation allowance of $8.7 million and $3.0 million has been applied against the deferred state tax benefits at December 31, 2011 and 2010, respectively.

At December 31, 2011 and 2010, the Company had a capital loss carryforward of $6.7 million and $3.8 million, respectively, which are available to offset future consolidated capital gains.  Due to uncertainties regarding the realization of the capital loss carryforward, a valuation allowance of $6.7 million and $3.8 million has been applied against the deferred tax benefit at December 31, 2011 and 2010, respectively.

As of December 31, 2011 and 2010, the Company had unrecognized tax benefits of $0.1 million and $0.1 million, respectively, all of which would impact the effective tax rate, if recognized.  Unrecognized tax benefits are recorded in other long term liabilities at December 31, 2011 and 2010.

F-46

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

	Successor					Predecessor
	For the Year Ended December 31,		For the Ten Months Ended December 31,			For the Two Months Ended February 28,
	2011		2010			2010
	(In thousands)
Beginning balance	$	102	$	105		$	874
Additions based on tax positions related to the current year	—		—			—
Reductions based on tax positions taken in previous years	—		—			—
Additions based on tax positions taken in previous years	—		—			—
Settlements	—		(3		)	(769		)
Reductions for lapse of statute of limitations	—		—			—
Ending balance	$	102	$	102		$	105

The Company includes the interest expense or income, as well as potential penalties on unrecognized tax benefits, as components of income tax expense in the consolidated statement of operations.  The total amount of accrued interest related to uncertain tax positions, net of the deferred tax benefit, at December 31, 2011 and 2010 was $19 thousand and $19 thousand, respectively.  There is a reasonable possibility that these unrecognized tax benefits could reverse within the next twelve months.

The Company files a federal and various state income tax returns. The Company’s federal income tax returns for 2008 to 2010 are open tax years under the statute of limitations.  The Company’s federal income tax return for 2008 has been audited.  The Company files in numerous state jurisdictions with varying statutes of limitations open from 2007 to 2010.

18.Warrants

In connection with the Plan, holders of allowed Class 9(a) equity interests received warrants to purchase up to an aggregate amount of 450,000 shares of common stock of the successor company at an exercise price initially set at $40.94, subject to adjustment exercisable through the earlier of March 15, 2015, or upon the occurrence of an acceleration event.  Events which would result in adjustment to the exercise price of the warrants would include a merger of the Company into or a consolidation of the Company with another entity, a sale of all or substantially all of the Company’s assets, or a merger of another entity into the company.  Each warrant entitles the registered owner thereof to purchase one share of common stock of the successor company.  As of December 31, 2011, holders of the warrants had exercised 498 of the warrants.

As provided in ASC 825-20, the warrants are considered equity because they can only be physically settled in company shares, or can be settled in unregistered shares.  The Company has adequate authorized shares to settle the outstanding warrants and each warrant is fixed in terms of settlement to one share of company stock subject only to remote contingency adjustment factors designed to assure the relative value in terms of shares remains fixed.

19.Stock-Based Compensation Plans

The Equity Incentive Plan

At December 31, 2011, the Company maintained one stock-based compensation plan, the Aventine Renewable Energy Holdings, Inc. 2010 Equity Incentive Plan (the “Equity Incentive Plan”).  The Equity Incentive Plan was adopted by the Board effective March 15, 2010, and provides for the grant of awards in the form of stock options, restricted stock or units, stock appreciation rights and other equity-based awards to directors, officers, employees and consultants or advisors (and prospective directors, officers, employees and consultants or advisors) of the Company or its affiliates at the discretion of the Board of Directors (the

F-47

“Board”) or the Compensation Committee of the Board.  The term of awards granted under the Equity Incentive Plan is determined by the Board or by the Compensation Committee of the Board, and cannot exceed ten years from the date of the grant.  The maximum number of shares of common stock that may be issued under the Equity Compensation Plan is limited to 855,000.  Unless terminated sooner, the Equity Incentive Plan will continue in effect until March 15, 2020.

The Predecessor Plan

The Predecessor’s stock-based compensation plan, 2003 Stock Incentive Plan (the “Predecessor Plan”) was adopted by the Predecessor’s 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 Predecessor Plan provided 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 Predecessor’s Plan was terminated by the Predecessor Board on February 23, 2010, pursuant to Article 16 of the Predecessor’s Plan.  Upon emergence from Chapter 11 bankruptcy protection, the Plan resulted in the cancellation of the existing equity securities.  As of the Effective Date, 1,573 options, 65 restricted stock units, and 76 restricted shares (all in thousands) were cancelled.  The Company recognized $277 thousand of stock-based compensation expense during the two months ended February 28, 2010, and the remaining $2.4 million of unrecognized expense was recorded as part of the Plan effects.

Pre-tax stock-based compensation expense for the year ended December 31, 2011, was approximately $5.4 million, which was charged to selling, general, and administrative expense. Pre-tax stock-based compensation expense for the ten months ended December 31, 2010, was approximately $7.8 million, which was charged to selling, general and administrative expense.  For the two months ended February 28, 2010, the Predecessor recognized $277 thousand of pre-tax stock-based compensation expense, of which $86 thousand was charged to cost of sales and $191 thousand was charged to selling, general and administrative expense.  Pre-tax stock-based compensation expense for the year ended December 31, 2009, was approximately $2.5 million, of which $0.4 million was charged to cost of goods sold and $2.1 million was charged to selling, general and administrative expense.

The Company recorded pre-tax stock-based compensation expense for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, as follows:

F-48

	Successor				Predecessor
	For the Year Ended December 31,		For the Ten Months Ended December 31,		For the Two Months Ended February 28,		For the Year Ended December 31,
	2011		2010		2010		2009
	(In millions)
Stock-based compensation expense:
Non-qualified options	$	0.7	$	3.2	$	0.3	$	2.2
Restricted stock	0.6		2.6		—		0.2
Restricted stock units	1.3		2.0		—		0.1
Hybrid equity units	2.8		—		—		—
Total	$	5.4	$	7.8	$	0.3	$	2.5

As of December 31, 2011, the Company had not yet recognized compensation expense on the following non-vested awards:

	December 31, 2011			December 31, 2010
	Non-recognized Compensation		Average Remaining Recognition Period	Non-recognized Compensation		Average Remaining Recognition Period
	(In millions)		(In years)	(In millions)		(In years)
Non-qualified options	$	0.4	0.9	$	2.2	1.3
Restricted stock	0.2		0.9	0.8		1.4
Restricted stock units	0.1		0.8	2.4		1.0
Hybrid equity units	1.4		3.1	—		—
Total	$	2.1	2.2	$	5.4	1.3

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

The determination of the fair value of the stock- related awards, using the Option Pricing Model for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, incorporated the assumptions in the following table for hybrid equity units granted in 2011, and stock options granted for 2010 and 2009:

F-49

	Successor				Predecessor
	For the Year Ended December 31,			For the Ten Months Ended December 31,	For the Two Months Ended February 28,		For the Year Ended December 31,
	2011			2010	2010		2009
Expected stock price volatility	99		%	63.13% - 85.53%	—		58		%
Expected life (in years)	3.7			3-6	—		6.5
Risk-free interest rate	1.4		%	0.57% -2.42%	—		2.17		%
Expected dividend yield	0.0		%	0.0%	—		0.0		%
Weighted average fair value	$	17.67		16.47	$	—	$	0.10

The following table summarizes stock options outstanding and changes during the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009:

	Share (in thousands)		Weighted- Average Exercise Price		Weighted- Average Remaining Life (years)	Aggregate Intrinsic Value (in thousands)
Predecessor:
Options outstanding — December 31, 2008	3,894		$	7.62	6.7	$	422
Options exercisable — December 31, 2008	2,059		$	4.83	5.7	$	405
Granted	50		$	0.18	—	—
Exercised	(85	)	$	0.23	—	—
Cancelled or expired	(1,274	)	$	13.02	—	—
Options outstanding — December 31, 2009	2,585		$	5.05	3.7	$	130
Options exercisable — December 31, 2009	2,070		$	3.86	2.7	$	121
Granted	—		—		—	—
Exercised	—		—		—	—
Cancelled or expired	2,070		$	3.86	—	—
Options outstanding — February 28, 2010	—		—		—	$	—
Options exercisable — February 28, 2010	—		—		—	$	—
Successor:
Granted	326		$	43.85	—	—
Exercised	—		—		—	—
Cancelled or expired	—		—		—	—
Options outstanding — December 31, 2010	326		$	43.85	9.5	$	—
Options exercisable — December 31, 2010	107		$	44.74	9.6	$	—
Granted	—		$	—	—	$	—
Exercised	—		$	—	—	$	—
Cancelled or expired	(23	)	$	37.26	—	$	—
Options outstanding — December 31, 2011	303		$	44.35	6.3	$	—
Options exercisable — December 31, 2011	252		$	44.34	5.9	$	—

F-50

Restricted stock award activity for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009 is summarized below:

	Shares (in thousands)		Weighted- Average Grant Date Fair Value per Award
Predecessor:
Unvested restricted stock awards — January 1, 2009	59.1		$	15.97
Granted	—		—
Vested	(16.8	)	17.41
Cancelled or expired	(3.0	)	17.29
Unvested restricted stock awards — December 31, 2009	39.3		$	15.26
Granted	—		—
Vested	—		—
Cancelled or expired	(39.3	)	15.26
Unvested restricted stock awards — February 28, 2010	—		$	—
Successor:
Granted	123.0		27.27
Vested	(62.0	)	25.80
Cancelled or expired	—		—
Unvested restricted stock awards — December 31, 2010	61.0		$	28.75
Granted	—		—
Vested	(35.0	)	27.19
Cancelled or expired	—		—
Unvested restricted stock awards — December 31, 2011	26.0		$	30.78

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.  Restricted stock unit award activity for the year ended December 31, 2011, the ten months ended December 31, 2010, the two months ended February 28, 2010, and the year ended December 31, 2009, is summarized below:

F-51

	Shares (in thousands)		Weighted- Average Grant Date Fair Value per Award
Predecessor:
Unvested restricted stock unit awards — January 1, 2009	46.5		$	6.88
Granted	—		—
Vested	(32.4	)	7.55
Cancelled or expired	—		—
Unvested restricted stock unit awards — December 31, 2009	14.1		$	5.33
Granted	—		—
Vested	—		—
Cancelled or expired	(14.1	)	5.33
Unvested restricted stock unit awards — February 28, 2010	—		$	—
Successor:
Granted	173.0		25.53
Vested	(21.0	)	24.94
Cancelled or expired	—		—
Unvested restricted stock unit awards — December 31, 2010	152.0		$	25.62
Granted	18.0		12.00
Vested	(156.0	)	23.89
Cancelled or expired	—		—
Unvested restricted stock unit awards — December 31, 2011	14.0		$	27.50

	Shares (in thousands)		Weighted- Average Grant Date Fair Value per Award
Successor:
Vested restricted stock unit awards — February 28, 2010	—		$	—
Vested	21.0		24.94
Converted into shares of common stock	—		—
Vested restricted stock unit awards — December 31, 2010	21.0		$	24.94
Vested	156.0		23.89
Converted into shares of common stock	(128.0	)	24.94
Vested restricted stock unit awards — December 31, 2011	49.0		$	21.62

For 2011 and beyond, the Board adopted a program of annual grants of hybrid equity units. Hybrid equity units represent the right to receive shares of stock in the future, depending upon the stock price on the measurement date.  Each unit granted for this year will translate into up to one share, depending on the average closing share price for the last 15 trading days of 2014, denoted as “S” in the following formula:

# Shares = # Units x (1 – 19.6/S)

For example, if a manager is granted 10,000 units, and S equals $40, then the manager would receive 5,100 shares (i.e., 10,000 units x (1 – 19.6/40) = 5,100).  If the stock price ends up higher, then the participant would receive more shares; if the stock price were lower, he or she would receive fewer shares.  If the stock price falls below $19.60, the participant would be granted no shares.

Hybrid equity unit activity for the year ended December 31, 2011, is summarized below.  There was no Hybrid equity activity for the ten months ended December 31, 2010, the two months ended February 28, 2010, or the year ended December 31, 2009.

F-52

	Units (in thousands)		Weighted- Average Grant Date Fair Value per Award
Granted	276		$	17.67
Vested	(177	)	$	17.67
Cancelled or expired	(2	)	$	17.67
Unvested hybrid equity units at December 31, 2011	97		$	17.67

20.Asset Purchase Agreement

On August 6, 2010, the Company and Riverland entered into the Purchase Agreement pursuant to which the Company acquired substantially all of the assets, and assumed specified liabilities, of Riverland for a purchase price of $16.5 million.  The assets comprised a 38 mgpy nameplate ethanol production facility located in Canton, Illinois and included real property at the plant site as well as surrounding parcels.  Affiliates of certain holders of the Company’s debt and equity securities hold a controlling interest in Riverland.  The acquisition closed on August 6, 2010.  The Purchase Agreement includes customary representations, warranties and indemnification provisions. The assets acquired have been included in construction in progress, as additional capital expenditures are necessary prior to putting them into service.

21.Quarterly Results of Operations (Unaudited)

The following is a summary of the Company’s unaudited quarterly results of operations for the years ended December 31, 2011 and 2010:

	Successor
	2011 Fiscal Quarter
	First			Second			Third			Fourth
	(In thousands, except per share data)
Net sales	$	198,104		$	213,019		$	221,604		$	254,860
Gross profit (loss)	$	5,368		$	(6,464	)	$	9,118		$	22,188
Net income (loss) (1)	$	(19,261	)	$	(23,882	)	$	(11,177	)	$	10,930
Income (loss) per common share:
Basic	$	(2.24	)	$	(2.71	)	$	(1.23	)	$	1.14
Diluted	$	(2.24	)	$	(2.71	)	$	(1.23	)	$	1.14

	Predecessor			Successor
	2010 Fiscal Quarter
	Two Months Ended February 28			One Month Ended March 31
	First						Second			Third			Fourth
	(In thousands, except per share data)
Net sales	$	77,675		$	36,974		$	96,904		$	97,460		$	139,221
Gross profit (loss)	$	10,989		$	(341	)	$	1,453		$	7,022		$	12,674
Net loss (1)	$	(266,293	)	$	(7,100	)	$	(9,259	)	$	(6,641	)	$	(2,464	)
Loss per common share:
Basic	$	(6.14	)	$	(0.82	)	$	(1.06	)	$	(0.76	)	$	(0.29	)
Diluted	$	(6.14	)	$	(0.82	)	$	(1.06	)	$	(0.76	)	$	(0.29	)

(1)  During the two months ended February 28, 2010, the Company recognized a $387,655 loss due to fresh start accounting adjustments and a $136,574 gain due to plan effects.  See Note 2.

F-53

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Aventine Renewable Energy Holdings, Inc.

We have audited the accompanying consolidated balance sheets of Aventine Renewable Energy Holdings, Inc. and subsidiaries as of December 31, 2011 and 2010 (Successor), and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2011 (Successor), the ten-month period ended December 31, 2010 (Successor), the two-month period ended February 28, 2010 (Predecessor) and year ended December 31, 2009 (Predecessor). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Aventine Renewable Energy Holdings, Inc. and subsidiaries at December 31, 2011 and 2010 (Successor), and the consolidated results of their operations and their cash flows for the year ended December 31, 2011 (Successor), the ten-month period ended December 31, 2010 (Successor), the two-month period ended February 28, 2010 (Predecessor) and year ended December 31, 2009 (Predecessor), in conformity with U.S. generally accepted accounting principles.

	/s/ Ernst & Young LLP
Dallas, Texas
March 8, 2012

F-54

EXHIBIT INDEX

Exhibit Number	Description
2.1	Debtor’s First Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code Dated as of January 13, 2009 (incorporated by reference to Exhibit 2.1 of Aventine’s Current Report on Form 8-K filed on March 2, 2010).
2.2	Asset Purchase Agreement, dated August 6, 2010, between New CIE Energy Opco, LLC and Aventine Renewable Energy Holdings, Inc. (incorporated by reference to Exhibit 2.2 of Aventine’s Registration Statement on Form S-1 (Reg. No. 333-169301) filed on September 10, 2010).
3.1	Third Amended and Restated Certificate of Incorporation of Aventine Renewable Energy Holdings, Inc. (incorporated by reference to Exhibit 3.1 to Aventine’s Current Report on Form 8-K filed on March 19, 2010).
3.2	Amended and Restated Bylaws of Aventine Renewable Energy Holdings, Inc. (incorporated by reference to Exhibit 3.2 to Aventine’s Current Report on Form 8-K filed on March 19, 2010).
4.1	Indenture, dated as of March 15, 2010, among Aventine Renewable Energy Holdings, Inc., the guarantors named therein and Wilmington Trust FSB, and form of note (incorporated by reference to Exhibit 4.1 of Aventine’s Current Report on Form 8-K filed on March 19, 2010).
4.2	Registration Rights Agreement dated as of March 15, 2010, by and among Aventine Renewable Energy Holdings, Inc., Brigade Capital Management, LLC, Whitebox Advisors LLC and Senator Investment Group LP (incorporated by reference to Exhibit 4.2 of Aventine’s Current Report on Form 8-K filed on March 19, 2010).
4.3	Registration Rights Agreement dated as of March 15, 2010, by and among Aventine Renewable Energy Holdings, Inc., Aventine Renewable Energy, Inc., Aventine Renewable Energy — Aurora West, LLC, Nebraska Energy, L.L.C., Aventine Renewable Energy — Mt. Vernon, LLC, Aventine Power, LLC, Brigade Capital Management, LLC, Whitebox Advisors LLC, and Senator Investment Group LP (incorporated by reference to Exhibit 4.3 of Aventine’s Current Report on Form 8-K filed on March 19, 2010).
4.4	Warrant Agreement, dated as of March 15, 2010, between Aventine Renewable Energy Holdings, Inc. and American Stock Transfer & Trust Company, LLC, as warrant agent (including the form of Warrant Certificate set forth in Exhibit A thereto) (incorporated by reference to Exhibit 4.4 of Aventine’s Current Report on Form 8-K filed on March 19, 2010).
4.5	Registration Rights Agreement, dated as of August 19, 2010, by and among Aventine Renewable Energy Holdings, Inc., Aventine Renewable Energy, Inc., Aventine Renewable Energy—Aurora West, LLC, Nebraska Energy, L.L.C., Aventine Renewable Energy—Mt. Vernon, LLC, Aventine Power, LLC, Brigade Capital Management, LLC and Senator Investment Group LP (incorporated by reference to Exhibit 4.5 of Aventine’s Registration Statement on Form S-1 (Reg. No. 333-169301) filed on September 10, 2010).

90

10.1	Revolving Credit and Security Agreement, dated as of March 15, 2010, among Aventine Renewable Energy Holdings, Inc., Aventine Renewable Energy — Aurora West, LLC, Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC, Aventine Power, LLC and Nebraska Energy, L.L.C., as borrowers, and PNC Bank, National Association, as lender and as agent (incorporated by reference to Exhibit 10.1 of Aventine’s Amendment No. 1 to Registration Statement on Form S-1 (Reg. No. 333-169301) filed on December 14, 2010).
10.2	First Amendment to Revolving Credit and Security Agreement, dated as of August 6, 2010, among Aventine Renewable Energy Holdings, Inc., Aventine Renewable Energy—Aurora West, LLC, Aventine Renewable Energy, Inc., Aventine Renewable Energy—Mt. Vernon, LLC, Aventine Power, LLC and Nebraska Energy, L.L.C., as borrowers, and PNC Bank, National Association, as lender and as agent (incorporated by reference to Exhibit 10.2 of Aventine’s Amendment No. 2 to Registration Statement on Form S-1 (Reg. No. 333-169301) filed on December 14, 2010).
10.3	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.2 of Aventine’s Current Report on Form 8-K filed on March 19, 2010).
10.4	Aventine Renewable Energy Holdings, Inc. 2010 Equity Incentive Plan (incorporated by reference to Exhibit 10.3 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*
10.5	Aventine Renewable Energy Holdings, Inc. Director Compensation Plan (incorporated by reference to Exhibit 10.4 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*
10.6	Employment Agreement, dated March 15, 2010, between Aventine Renewable Energy Holdings, Inc. and Thomas Manuel (incorporated by reference to Exhibit 10.5 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*
10.7	Employment Agreement, dated March 15, 2010, between Aventine Renewable Energy Holdings, Inc. and Benjamin Borgen (incorporated by reference to Exhibit 10.6 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*
10.8	Stock Option Agreement, dated March 15, 2010, between Aventine Renewable Energy Holdings, Inc. and Thomas Manuel (incorporated by reference to Exhibit 10.7 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*
10.9	Form of Stock Option Agreement, between Aventine Renewable Energy Holdings, Inc. and Benjamin Borgen (incorporated by reference to Exhibit 10.8 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*
10.10	Restricted Stock Award Agreement, dated March 15, 2010, between Aventine Renewable Energy Holdings, Inc. and Thomas Manuel (incorporated by reference to Exhibit 10.9 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*
10.11	Form of Restricted Stock Award Agreement, between Aventine Renewable Energy Holdings, Inc. and Benjamin Borgen (incorporated by reference to Exhibit 10.10 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*
10.12	Restricted Stock Unit Award Agreement, dated March 15, 2010, between Aventine Renewable Energy Holdings, Inc. and Thomas Manuel (incorporated by reference to Exhibit 10.11 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*

91

10.13	Form of Restricted Stock Unit Award Agreement for Directors (incorporated by reference to Exhibit 10.12 of Aventine’s Quarterly Report on Form 10-Q filed on May 17, 2010).*
10.14	Short Form Contract, dated April 23, 2010, between Fagen, Inc. and Aventine Renewable Energy — Aurora West, L.L.C. (incorporated by reference to Exhibit 10.7 of Aventine’s Quarterly Report on Form 10-Q filed on August 5, 2010).†
10.15	Short Form Contract, dated May 4, 2010, between Fagen, Inc. and Aventine Renewable Energy — Mt. Vernon, L.L.C. (incorporated by reference to Exhibit 10.8 of Aventine’s Quarterly Report on Form 10-Q filed on August 5, 2010).†
10.16	Construction Agreement, dated May 14, 2010, between Aventine Renewable Energy — Aurora West, L.L.C. and Fagen, Inc. (incorporated by reference to Exhibit 10.9 of Aventine’s Quarterly Report on Form 10-Q filed on August 5, 2010).†
10.17	Construction Agreement, dated May 17, 2010, between Aventine Renewable Energy — Mt. Vernon, L.L.C. and Fagen, Inc. (incorporated by reference to Exhibit 10.10 of Aventine’s Quarterly Report on Form 10-Q filed on August 5, 2010).†
10.18	Employment Agreement, dated May 5, 2010, between Aventine Renewable Energy Holdings, Inc. and John Castle (incorporated by reference to Exhibit 10.1 of Aventine’s Quarterly Report on Form 10-Q filed on August 5, 2010).*
10.19	Form of Stock Option Agreement between Aventine Renewable Energy Holdings, Inc. and John Castle (incorporated by reference to Exhibit 10.3 of Aventine’s Quarterly Report on Form 10-Q filed on August 5, 2010).*
10.20	Restricted Stock Award Agreement between Aventine Renewable Energy Holdings, Inc. and John Castle (incorporated by reference to Exhibit 10.4 of Aventine’s Quarterly Report on Form 10-Q filed on August 5, 2010).*
10.21	Letter of Intent, dated June 10, 2010, among Aventine Renewable Energy Holdings, Inc., New CIE Energy Opco, LLC Whitebox Credit Arbitrage Fund, L.P. and Whitebox Credit Arbitrage Fund, LTD. (incorporated by reference to Exhibit 10.6 of Aventine’s Quarterly Report on Form 10-Q filed on August 5, 2010).*
10.22	Backstop Commitment Agreement, dated August 2, 2010, among Aventine Renewable Energy Holdings, Inc., Aventine Renewable Energy, Inc., Aventine Renewable Energy—Aurora West, LLC, Aventine Renewable Energy—Mt. Vernon, LLC, Aventine Power, LLC and Nebraska Energy, L.L.C., Brigade Capital Management, LLC and Senator Investment Group LP (incorporated by reference to Exhibit 10.22 of Aventine’s Registration Statement on Form S-1 (Reg. No. 333-169301) filed on September 10, 2010).
10.23	Lease Agreement, dated as of October 31, 2006 by and between the Indiana Port Commission and Aventine Renewable Energy — Mt. Vernon, LLC (“Mt. Vernon Lease Agreement”) (incorporated by reference to Exhibit 10.1 to Aventine’s Annual Report on Form 10-K filed on March 5, 2007).
10.23.1	First Amendment to Mt. Vernon Lease Agreement, dated as of June 14, 2007 (incorporated by reference to Exhibit 10.1.1 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008).
10.23.2	Second Amendment to Mt. Vernon Lease Agreement, dated as of October 18, 2007 (incorporated by reference to Exhibit 10.1.2 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008).

92

10.23.3	Third Amendment to Mt. Vernon Lease Agreement, dated as of January 26, 2008 (incorporated by reference to Exhibit 10.1.3 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008).
10.23.4	Fourth Amendment to Mt. Vernon Lease Agreement, dated as of June 19, 2008 (incorporated by reference to Exhibit 10.1.4 to Aventine’s Annual Report on Form 10-K filed on March 16, 2009).
10.23.5	Fifth Amendment to Mt. Vernon Lease Agreement, dated as of December 18, 2008 (incorporated by reference to Exhibit 10.1.5 to Aventine’s Annual Report on Form 10-K filed on March 16, 2009).
10.23.6	Sixth Amendment to Mt. Vernon Lease Agreement, dated as of February 12, 2009 (incorporated by reference to Exhibit 10.1.6 to Aventine’s Annual Report on Form 10-K filed on March 16, 2009).
10.23.7	Seventh Amendment to Mt. Vernon Lease Agreement, dated as of April 23, 2009 (incorporated by reference to Exhibit 10.1 of Aventine’s Quarterly Report on Form 10-Q filed on August 10, 2009).
10.23.8	Eighth Amendment to Mt. Vernon Lease Agreement, dated as of December 10, 2009 (incorporated by reference to Exhibit 10.23.8 of Aventine’s Registration Statement on Form S-1 (Reg. No. 333-169301) filed on September 10, 2010).
10.24	Form of Restricted Stock Unit Award Agreement, dated as of October 13, 2010, between Aventine Renewable Energy Holdings, Inc. and Benjamin Borgen (incorporated by reference to Exhibit 10.24 of Aventine’s Amendment No. 1 to Registration Statement on Form S-1 (Reg. No. 333-169301) filed on December 14, 2010).
10.25	Agreement Relating to Master Development Agreement, Grain Supply Agreements and Real Estate Option, dated as of March 23, 2010, by and among Nebraska Energy, LLC, Aventine Renewable Energy Holdings, Inc., Aventine Renewable Energy—Aurora West LLC and Aurora Cooperative Elevator Company (incorporated by reference to Exhibit 10.25 of Aventine’s Amendment No. 1 to Registration Statement on Form S-1 (Reg. No. 333-169301) filed on December 14, 2010).
10.26	Aventine Renewable Energy, Inc. and Affiliates Key Executive Incentive Plan (incorporated by reference to Exhibit 10.26 of Aventine’s Amendment No. 1 to Registration Statement on Form S-1 (Reg. No. 333-169301) filed on December 14, 2010).†
10.27	Senior Secured Term Loan Credit Agreement dated as of December 22, 2010 among Aventine Renewable Energy Holdings, Inc., as borrower, Citibank, N.A., as administrative agent and collateral agent, the other lenders party thereto, Citigroup Global Markets Inc. and Jefferies Finance LLC as joint lead arrangers and joint book-runners, and Citibank, N.A. and Jefferies Finance LLC, as co-syndication agents (incorporated by reference to Exhibit 10.1 of Aventine’s Current Report on Form 8-K filed on December 12, 2010).
10.28	Second Amendment and Joinder to Revolving Credit and Security Agreement dated as of December 22, 2010 among Aventine Renewable Energy Holdings, Inc. and PNC Bank National Association, as agent for lenders (incorporated by reference to Exhibit 10.2 of Aventine’s Current Report on Form 8-K filed on December 12, 2010).

93

10.29	Third Amendment to the Revolving Credit and Security Agreement, dated as of February 28, 2011, among Aventine Renewable Energy Holdings, Inc., Aventine Renewable Energy - Aurora West, LLC, Aventine Renewable Energy, Inc., Aventine Renewable Energy - Mt. Vernon, LLC, Aventine Power, LLC, Nebraska Energy, L.L.C., and Aventine Renewable Energy — Canton, LLC, as borrowers, and PNC Bank, National Association, as lender and as agent (incorporated by reference to Exhibit 10.1 of Aventine’s Current Report on Form 8-K filed on March 4, 2011).
10.30	Commitment Letter, effective as of March 25, 2011, between Aventine Renewable Energy Holdings, Inc. and Macquarie Capital (USA) Inc. (incorporated by reference to Exhibit 10.1 of Aventine’s Quarterly Report on Form 10-Q filed on May 10, 2011).
10.31	Incremental Amendment to the Senior Secured Term Loan Credit Agreement, dated as of April 7, 2011, by and among Aventine Renewable Energy Holdings, Inc., Citibank, N.A., as administrative agent for the lenders under the Senior Secured Term Loan Credit Agreement, and Macquarie Bank Limited, as lender (incorporated by reference to Exhibit 10.12 of Aventine’s Quarterly Report on Form 10-Q filed on May 10, 2011).
10.32	Mutual Release between Aventine Renewable Energy Holdings, Inc and Thomas Manuel, dated as of August 19, 2011 (incorporated by reference to Exhibit 10.1 of Aventine’s Current Report on Form 8-K filed on August 22, 2011.
10.33	Amendment No. 3 to the Senior Secured Term Loan Credit Agreement and Consent to Amendment and Restatement of Intercreditor Agreement, dated as of July 20, 2011, by and among Aventine Renewable Energy Holdings, Inc., the lenders parties to the Senior Secured Term Loan Credit Agreement, and Citibank, N.A., as administrative agent collateral agent for the lenders under the Senior Secured Term Loan credit Agreement (incorporated by reference to Exhibit 10.2 of Aventine’s Quarterly Report on Form 10-Q filed on November 22, 2011.
10.34	Amended and Restated Credit Agreement, dated as of July 20, 2011, by and among Wells Fargo Capital Finance, LLC, as agent and as lender, and Aventine Renewable Energy — Aurora West, LLC, Aventine Renewable Energy — Mt. Vernon, LLC, Aventine Renewable Energy — Canton, LLC, Aventine Power, LLC and Nebraska Energy, LLC, as borrowers (incorporated by reference to Exhibit 10.3 of Aventine’s Quarterly Report on Form 10-Q filed on November 9, 2011.
10.35	Employment Agreement between Aventine Renewable Energy Holdings, Inc. and John Castle, dated as of November 21, 2011 (incorporated by reference to Exhibit 10.1 of Aventine’s Current Report on Form 8-K filed on November 23, 2011).
10.36	Employment Agreement between Aventine Renewable Energy Holdings, Inc. and Calvin Stewart, dated as of November 22, 2011 (incorporated by reference to Exhibit 10.1 of Aventine’s Current Report on Form 8-K filed on November 23, 2011).
21.1	List of subsidiaries of the registrant.
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.

94

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.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

*Compensatory plan or arrangement.

†Portions of the Exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

95