Share Name	Share Symbol	Market	Type
Aventine Renew Enrgy	NYSE:AVR	NYSE	Ordinary Share

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for the quarterly period ended September 30, 2008

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 of Incorporation)		(IRS Employer Identification No.)

120 North Parkway
Pekin, Illinois		61554
(Address of Principal Executive Offices)		(Zip Code)

(309) 347-9200

(Registrant’s Telephone Number, including Area Code)

Indicate by checkmark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YES x NO o

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See 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 x	Non-accelerated filer o	Smaller reporting company o

		(Do not check if a smaller reporting company)

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

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

Class		Outstanding as of November 5, 2008
Common Stock, $0.001 Par Value		42,970,988 Shares

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FORM 10-Q

QUARTERLY REPORT

TABLE OF CONTENTS

		Page No.

	PART I

Item 1.	Financial Statements
	Condensed Consolidated Statements of Operations (Unaudited) - Three-month and nine-month periods ended September 30, 2008 and 2007	1
	Condensed Consolidated Balance Sheets – September 30, 2008 (Unaudited) and December 31, 2007	2
	Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine-month periods ended September 30, 2008 and 2007	3
	Notes to Unaudited Condensed Consolidated Financial Statements	4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37

Item 4.	Controls and Procedures	40

	PART II

Item 1.	Legal Proceedings	41

Item 1A.	Risk Factors	41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42

Item 3.	Defaults Upon Senior Securities	42

Item 4.	Submission of Matters to a Vote of Security Holders	42

Item 5.	Other Information	42

Item 6.	Exhibits	42

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
(In thousands except per share amounts)	2008			2007			2008			2007

Net sales	$	599,520		$	360,674		$	1,711,059		$	1,192,250
Cost of goods sold	605,990			362,401			1,660,586			1,138,133
Gross profit (loss)	(6,470		)	(1,727		)	50,473			54,117
Selling, general and administrative expenses	8,763			9,384			27,771			27,761
Loss related to auction rate securities	—			—			31,601			—
Other (income)	(405		)	(169		)	(2,799		)	(847		)
Operating income (loss)	(14,828		)	(10,942		)	(6,100		)	27,203
Other income (expense):
Interest income	254			3,576			2,999			9,111
Interest expense	(235		)	(5,359		)	(3,751		)	(12,716		)
Other non-operating income (loss)	18,367			(953		)	6,114			5,055
Minority interest	725			(103		)	1,230			(1,346		)
Income (loss) before income taxes	4,283			(13,781		)	492			27,307
Income tax expense (benefit)	1,797			(16,776		)	10,719			(3,235		)
Net income (loss)	$	2,486		$	2,995		$	(10,227	)	$	30,542

Per share data:
Income (loss) per common share – basic:	$	0.06		$	0.07		$	(0.24	)	$	0.73
Basic weighted average number of common shares	41,971			41,949			41,927			41,891

Income (loss) per common share – diluted:	$	0.06		$	0.07		$	(0.24	)	$	0.72
Diluted weighted average number of common and common equivalent shares	42,010			42,385			41,958			42,497

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

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(In thousands except share amounts)	September 30, 2008			December 31, 2007
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	36,255		$	17,171
Short-term investments	—			211,500
Accounts receivable	77,491			73,058
Inventories	119,644			81,488
Income tax receivable	1,850			11,962
Prepaid expenses and other current assets	9,756			12,816
Total current assets	244,996			407,995
Property, plant and equipment, net	102,821			111,867
Construction in process	444,683			226,410
Net deferred tax assets	—			1,196
Other assets	14,851			14,717
Total assets	$	807,351		$	762,185
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	124,929		$	91,871
Accrued interest	15,000			7,500
Accrued liabilities	4,184			3,625
Other current liabilities	10,449			1,622
Total current liabilities	154,562			104,618
Senior unsecured 10% notes due April 2017	300,000			300,000
Minority interest	8,601			9,832
Net deferred tax liabilities	1,048			—
Other long-term liabilities	3,577			3,864
Total liabilities	467,788			418,314
Stockholders’ equity
Common stock, par value $0.001 per share; 185,000,000 shares authorized; 41,970,988 and 41,734,223 shares issued and outstanding as of September 30, 2008 and December 31, 2007, respectively, net of 21,548,640 shares held in treasury as of September 30, 2008 and December 31, 2007	42			42
Preferred stock, 50,000,000 shares authorized, no shares issued or outstanding	—			—
Additional paid-in capital	285,123			279,218
Retained earnings	54,708			64,935
Accumulated other comprehensive loss	(310		)	(324		)
Total stockholders’ equity	339,563			343,871
Total liabilities and stockholders’ equity	$	807,351		$	762,185

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

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
(In thousands)	2008			2007

Operating Activities
Net income (loss)	$	(10,227	)	$	30,542
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss related to auction rate securities	31,601			—
Depreciation and amortization	10,726			9,765
Lower of cost or market adjustment related to inventory	4,538			1,600
Minority interest	(1,230		)	1,346
Stock-based compensation expense	4,510			5,258
Deferred income tax	2,244			(7,939		)
Other	(376		)	139
Changes in operating assets and liabilities:
Accounts receivable, net	(4,433		)	31,929
Inventories	(42,694		)	4,664
Accounts payable and other liabilities	49,944			(29,235		)
Other changes in operating assets and liabilities	12,009			5,835
Net cash provided by operating activities	56,612			53,904

Investing Activities
Additions to property, plant and equipment, net	(221,980		)	(149,898		)
Investment in short-term securities	—			(183,943		)
Sale of short-term securities	179,899			—
Indemnification proceeds	3,039			—
Proceeds from the sale of property, plant and equipment	14			—
Net cash (used for) investing activities	(39,028		)	(333,841		)

Financing Activities
Proceeds from issuance of senior unsecured notes	—			300,000
Purchase of treasury stock	—			(991		)
Payment of debt issuance costs	—			(8,220		)
Proceeds from stock option exercises	—			508
Proceeds from the issuance of common stock	1,500			—
Distributions to minority shareholders	—			(1,727		)
Net cash provided by financing activities	1,500			289,570
Net increase in cash and cash equivalents	19,084			9,633
Cash and cash equivalents at beginning of period	17,171			29,791
Cash and cash equivalents at end of period	$	36,255		$	39,424

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

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(1) Basis of Reporting for Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements include the accounts of Aventine Renewable Energy Holdings, Inc. and its subsidiaries, which are collectively referred to as “Aventine”, the “Company”, “we”, “our” or “us”, unless the context otherwise requires. All significant intercompany transactions have been eliminated in consolidation.

We have prepared the unaudited condensed consolidated financial statements included herein pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to such rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.

The accompanying unaudited condensed consolidated financial statements presented herewith reflect all adjustments (consisting of only normal and recurring adjustments) which, in the opinion of management, are necessary for a fair presentation of the results of operations for the three and nine month periods ended September 30, 2008 and 2007. The results of operations for interim periods are not necessarily indicative of results to be expected for an entire year.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates.

As of September 30, 2008, the Company’s Summary of Critical Accounting Policies for the year ended December 31, 2007, which are detailed in the Company’s Annual Report on Form 10-K, have not changed.

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

(2) Recent Accounting Pronouncements

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

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periods within those years. Accordingly, we will adopt FSP EITF 03-6-1 in fiscal year 2009. We are currently evaluating the impact of FSP EITF 03-6-1 on the consolidated financial statements.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161 (“SFAS 161”), Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133 . SFAS 161 requires entities to provide greater transparency in derivative disclosures by requiring qualitative disclosure about objectives and strategies for using derivatives and quantitative disclosures about fair value amounts of and gains and losses on derivative instruments. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating SFAS 161, but does not expect it will have a material impact on the Company’s financial position or results of operations.

(3) Inventories

Inventories are as follows:

(In thousands)	September 30, 2008		December 31, 2007

Finished products	$	109,092	$	73,530
Work-in-process	3,904		2,035
Raw materials	3,785		2,757
Supplies	2,863		3,166
Totals	$	119,644	$	81,488

(4) Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets are as follows:

(In thousands)	September 30, 2008		December 31, 2007

Prepaid motor fuel taxes	$	1,041	$	5,061
Margin deposits on derivative instruments	3,952		4,013
Prepaid insurance	2,292		1,107
Prepaid ethanol	281		1,050
Current portion of deferred income taxes	827		854
Other prepaid expenses	1,363		731
Totals	$	9,756	$	12,816

(5) Other Assets

Other assets are as follows:

(In thousands)	September 30, 2008		December 31, 2007

Deferred debt issuance costs	$	6,902	$	7,533
Investments in marketing alliances	6,000		6,000
Funded status of pension plan	1,949		1,184
Totals	$	14,851	$	14,717

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Deferred debt issuance costs are subject to amortization. Original deferred debt issuance costs totaling $7.2 million relating to our 10% senior unsecured notes are being amortized utilizing a method which approximates the effective interest method over the life of the notes of 10 years, resulting in amortization expense of $0.7 million in 2008 and each year thereafter. Original deferred debt issuance costs totaling $0.9 million relating to our secured revolving credit facility are being amortized utilizing a method which approximates the effective interest method over the five year life of the facility, resulting in amortization expense of $0.2 million in 2008 and each year thereafter.

(6) Debt

The following table summarizes the Company’s long-term debt:

(In thousands)	September 30, 2008		December 31, 2007

Senior unsecured 10% notes due April 2017	$	300,000	$	300,000
Secured revolving credit facility	—		—
	300,000		300,000
Less short-term borrowings	—		—
Total long-term debt	$	300,000	$	300,000

Secured Revolving Credit Facility

Our liquidity facility consists of a five year secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent and a lender, of up to $200 million, subject to collateral availability, which, under certain circumstances, can be increased up to $300 million. Our secured revolving credit facility includes a $25 million sub-limit for letters of credit. The credit facility expires in March 2012, and, at September 30, 2008, was secured by substantially all of the Company’s assets, with the exception of the assets of Nebraska Energy, LLC.

Collateral availability is determined via a borrowing base, which includes a percentage of eligible receivables and inventory, and no more than $50 million of property, plant and equipment. The amount of property, plant and equipment which can be included in the borrowing base reduces at a rate of $1.8 million each quarter beginning with the quarter ending December 31, 2007. At September 30, 2008, the amount of property, plant and equipment which was eligible for inclusion in the calculation of the borrowing base was $42.9 million.

Borrowings generally bear interest, at our option, at the following rates (i) the Eurodollar rate plus a margin between 1.25% to 1.75%, depending on the average availability, or (ii) the greater of the prime rate or the federal funds rate plus 0.50%, plus a margin between 0.00% to 0.50%, depending on the average availability. Accrued interest is payable monthly on outstanding principal amounts, provided that accrued interest on Eurodollar loans is payable at the end of each interest period, but in no event less frequently than quarterly. In addition, fees and expenses are payable based on unused borrowing availability (0.25% to 0.375% per annum, depending on the average availability), outstanding letters of credit (1.375% to 1.875%, depending on the average availability) and administrative and legal costs.

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million, we must maintain a fixed charge coverage ratio of EBITDA (as defined under the agreement) less non-financed capital expenditures and taxes to fixed charges (scheduled payments of principal, interest expense and certain types of dividend and other payments) of at least 1.1 to 1.

The secured revolving credit facility contains customary events of default for credit facilities of this size and type, and includes, without limitation, payment defaults; defaults in performance of covenants or other agreements contained in the transaction documents; inaccuracies in representations and warranties; certain defaults, termination events or similar events; certain defaults with respect to any other Company indebtedness in excess of $5.0 million; certain bankruptcy or insolvency events; the rendering of certain judgments in excess of $5.0 million; certain ERISA events; certain change in control events and the defectiveness of any liens under the secured revolving credit facility. Obligations under the secured revolving credit facility may be accelerated upon the occurrence of an event of default.

As of September 30, 2008, we were in compliance with all covenants under our secured revolving credit facility, including the fixed charge coverage ratio. If we continue with our building expansion on our current timetable and within the expected cost and given our expectations for future EBITDA, we would not expect to be in compliance with the fixed charge coverage ratio covenant before the end of 2009 at the earliest and, therefore, would not have access to the last $50 million of availability. Failing to satisfy the fixed charge ratio does not constitute an event of default nor does it affect our ability to borrow amounts under the facility other than the last $50 million of commitments. We had no borrowings outstanding under our secured revolving credit facility at September 30, 2008, and $22.2 million of standby letters of credit outstanding, thereby leaving approximately $132.9 million in borrowing availability under our secured revolving credit facility as of that date (including the $50 million which we have said we do not expect to be able to access).

Senior Notes

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

The Notes have interest payments due semi-annually on April 1 and October 1 of each year, and are redeemable after the dates and at prices (expressed in percentages of principal amount on the redemption date), as set forth below:

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

In addition, at any time prior to April 1, 2010, we may redeem up to 35% of the principal amount of the Notes from time to time originally issued with the net cash proceeds of one or more sales of qualifying capital stock of the Company at a redemption price of 100% of the principal amount, together with accrued and unpaid interest to the redemption date, provided that at least 65% of the aggregate principal amount of the Notes originally issued remains outstanding immediately after such redemption and notice of any such redemption is mailed within 60 days of each such sale of capital stock. The terms

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of the Notes also contain restrictive covenants that limit our ability to, among other things, incur additional debt, sell or transfer assets, make certain investments or guarantees, enter into transactions with shareholders and affiliates, and pay future dividends.

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

(7) Other Current Liabilities

Other current liabilities are as follows:

(In thousands)	September 30, 2008		December 31, 2007

Income taxes payable	$	2,454	$	—
Deferred revenue	6,400		—
Accrued property taxes	441		578
Current portion of unearned commissions	424		424
Accrued sales tax	52		184
Current portion of deferred income taxes	556		379
Other accrued operating expenses	122		57
Totals	$	10,449	$	1,622

(8) Other Long-Term Liabilities

Other long-term liabilities are as follows:

(In thousands)	September 30, 2008		December 31, 2007

Accrued postretirement obligations	$	2,341	2,310
Unearned commissions	1,236		1,554
Totals	$	3,577	$	3,864

(9) Fair Value Measurements

SFAS 157

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

·	Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
·	Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability;
·	Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

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

The following table summarizes the valuation of our financial instruments which are carried at fair value by the above SFAS 157 pricing levels as of September 30, 2008:

			Fair Value Measurements at the Reporting Date Using
	Fair Value at September 30, 2008		Quoted Prices in Active Markets Using Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)

Cash and cash equivalents	$	36,255	$	36,255	—	—
Commodity futures contracts	$	2,865	$	2,865	—	—

The following table represents a reconciliation of the change in assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the nine months ended September 30, 2008.

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

In 2008, the Company recorded losses from Level 3 assets (auction rate securities) of $30.1 million. In addition, the Company also sold auction rate securities prior to these assets being classified as Level 3 assets incurring a loss of $1.5 million. The total losses incurred by the Company in 2008 related to auction rate securities were $31.6 million. This loss is included in “loss related to auction rate securities” in the unaudited Condensed Consolidated Statement of Operations. The Company holds no auction rate securities as of September 30, 2008.

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

The Company recorded net gains of $18.4 million and $6.1 million, respectively, for the three and nine month periods ended September 30, 2008 and net losses of $1.0 million for the three month period ended September 30, 2007 and net gains of $5.1 million for the nine month period ended

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September 30, 2007 under “other non-operating income” in the unaudited Condensed Consolidated Statements of Operations for the changes in the fair value of its derivative financial instrument positions.

SFAS 159

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

The carrying value of other financial instruments, including cash, accounts receivable 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 September 30, 2008 and December 31, 2007.

	As of September 30, 2008		As of December 31, 2007
	Carrying Value	Fair Value	Carrying Value	Fair Value
Investments at cost	6,000	n/a	6,000	n/a
Long-term debt	300,000	159,000	300,000	274,500

The Company’s investments accounted for under the cost method consist of minority positions in equity securities of other ethanol operating companies. These equity investments are recorded at cost, and it is not practical to estimate a fair value for these non-publicly traded companies. The Company monitors its investments for impairment by considering current factors, including the economic environment, market conditions, operational performance and other specific factors relating to the business underlying the investment, and records reductions in carrying values when necessary. Any impairment loss is reported under “Other income (expense)” in the consolidated statement of operations.

The fair value of our senior secured floating rate notes are based upon quoted closing market prices at the end of the period.

(10) Stock-Based Compensation Plans

The Company values its share-based payment 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 our stock price as well as the input of other subjective assumptions. The option-pricing model requires a number of assumptions, of which the most significant are expected stock price volatility, the expected pre-vesting forfeiture rate and the expected option term (the amount of time from the grant date until the options are exercised or expire). Expected volatility is normally calculated based upon actual historical stock price movements over the expected option term. Since we have a short-term history of stock price volatility as a public company, we calculate volatility by considering, among other things, the expected volatilities of public companies engaged in similar industries. Pre-vesting forfeitures had previously been estimated using a 3% forfeiture rate. However, beginning in the quarter ended September 30, 2008, we revised our estimated forfeiture rate to 6.4%, reflecting a higher actual experience rate since becoming a public company in 2006. The expected option term is calculated using the “simplified” method permitted by SAB 107. Our options have characteristics significantly different from those of traded options, and changes in the assumptions can materially affect the fair value estimates.

Pre-tax stock-based compensation expense for the three month periods ended September 30, 2008 and 2007 was approximately $0.6 million and $1.9 million, respectively. For the three month period ended September 30, 2008, the $0.6 million expense was charged to SG&A expense. For the

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three month period ended September 30, 2007, $1.8 million was charged to selling, general and administrative expense and $0.1 million was charged to cost of goods sold. Stock-based compensation expense was reduced in the three month period ended September 30, 2008 by approximately $1.2 million as a result of updating our expected forfeiture rate and the number of performance shares expected to vest. The adjustment made to stock-based compensation expense increased earnings per share by $0.02 per basic and fully diluted share for the three month period ended September 30, 2008. Stock-based compensation expense reduced earnings per share by $0.01 per basic and diluted share and by $0.03 per basic and diluted share for the three month periods ended September 30, 2008 and 2007, respectively. Pre-tax stock-based compensation expense for the nine month periods ended September 30, 2008 and 2007 was approximately $4.5 million and $5.3 million, respectively. For the nine month period ended September 30, 2008, $4.3 million was charged to SG&A expense and $0.2 million was charged to cost of goods sold. For the nine month period ended September 30, 2007, $5.2 million was charged to selling, general and administrative expense and $0.1 million was charged to cost of goods sold. Stock-based compensation expense reduced earnings per share by $0.07 per basic and fully diluted share for the nine month period ended September 30, 2008 and by $0.08 per basic and fully diluted share for the nine month period ended September 30, 2007. The Company recognized a tax benefit on its condensed consolidated statement of operations from stock-based compensation expense in the amount of $0.2 million and $0.7 million for the three month periods ended September 30, 2008 and 2007, respectively. For the nine month period ended September 30, 2008 and 2007, the Company recognized a tax benefit on its condensed consolidated statement of operations from stock-based compensation expense in the amount of $1.7 million and $2.1 million, respectively. The Company recorded pre-tax stock-based compensation expense for the three and nine month periods ended September 30, 2008 and 2007 as follows:

	Three months ended September 30,					Nine months ended September 30,
(in millions)	2008			2007		2008		2007

Stock-based compensation expense:
Non-qualified stock options	$	0.8		$	1.7	$	4.1	$	4.8
Restricted stock	0.1			0.1		0.3		0.3
Restricted stock units	0.1			—		0.1		0.1
Long-term incentive stock plan	(0.4		)	0.1		—		0.1
Totals	$	0.6		$	1.9	$	4.5	$	5.3

As of September 30, 2008 and 2007, the Company had not yet recognized compensation expense on the following non-vested awards:

	2008			2007
(in millions)	Non- recognized Compensation		Weighted Average Remaining Recognition Period (years)	Non- recognized Compensation		Weighted Average Remaining Recognition Period (years)

Non-qualified options	$	13.1	2.5	$	19.6	2.4
Restricted stock	0.8		3.3	1.1		4.1
Restricted stock units	0.3		1.6	0.2		1.0
Long-term incentive stock plan	0.4		1.3	1.4		1.7
Total	$	14.6	2.5	$	22.3	2.4

The determination of the fair value of the stock option awards, using the option pricing model, incorporated the assumptions in the following table for stock options granted during the quarter ended

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September 30, 2007. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant over the expected term. Expected volatility is calculated by considering, among other things, the expected volatilities of public companies engaged in similar industries. The expected option term is calculated using the “simplified” method permitted by SAB 107. The Company did not grant any stock options during the quarter ended September 30, 2008. Assumptions for options granted in the quarter ended September 30, 2007 are as follows:

	2007
Expected stock price volatility	58.0		%
Expected life (in years)	6.5
Risk-free interest rate	4.92		%
Expected dividend yield	0.0		%
Weighted average fair value	$	9.97

The following table summarizes stock options outstanding and changes during the nine month period ended September 30, 2008:

	Shares	Weighted Average Exercise Price		Weighted Average Remaining Life	Aggregate Intrinsic Value
	(in thousands)			(years)	(in thousands)

Options outstanding – January 1, 2008	3,516	$	8.10	7.4	$	—
Granted	568	6.85		10.0	—
Exercised	—	—		—	—
Cancelled or expired	190	14.31		—	—
Options outstanding – September 30, 2008	3,894	$	7.62	6.9	$	—
Options exercisable – September 30, 2008	1,988	$	4.83	5.9	$	—

The range of exercise prices of the exercisable options and outstanding options at September 30, 2008 are as follows:

Weighted Average Exercise Price	Number of Exercisable Options	Number of Outstanding Options	Weighted Average Remaining Life
	(in thousands)	(in thousands)	(years)

$0.23	992	1,006	4.8
$2.36 - $4.80	670	1,410	6.9
$7.05	—	478	9.4
$15.26 - $17.29	66	330	8.5
$22.15 - $22.50	244	630	7.5
$43.00	16	40	7.8
Totals	1,988	3,894	6.9

Restricted stock award activity for the nine months ended September 30, 2008 is summarized below:

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

Unvested restricted stock awards – January 1, 2008	76	$	16.29
Granted	—	—
Vested	17	17.41
Cancelled or expired	—	—
Unvested restricted stock awards – September 30, 2008	59	$	15.97

Restricted stock unit award activity for the nine months ended September 30, 2008 is summarized below:

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

Unvested Restricted stock unit awards –January 1, 2008	18	$	15.85
Granted	46	6.88
Vested	15	15.85
Cancelled or expired	—	—
Unvested restricted stock unit awards –September 30, 2008	49	$	7.79

(11) Interest Expense

The following table summarizes interest expense:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2008			2007			2008			2007

Interest expense	$	7,502		$	7,500		$	22,534		$	15,336
Amortization of deferred debt issuance costs	233			229			710			458
Capitalized interest	(7,500		)	(2,370		)	(19,493		)	(3,078		)
Interest expense, net	$	235		$	5,359		$	3,751		$	12,716

(12) Pension Expense

Defined Contribution Plans

We have 401(k) plans covering substantially all of our employees. We recognized expense with respect to these plans of $0.3 million and $0.2 million for the three month periods ended September 30, 2008 and 2007, respectively, and expense of $0.9 million for the nine month periods ended September 30, 2008 and 2007. Contributions made under our defined contribution plans include a match, at the Company’s discretion, of employee salaries contributed to the plans.

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Qualified Retirement Plan

The Company provides a non-contributory qualified defined benefit pension plan for its unionized employees at our Pekin, IL production facilities. The following table summarizes the components of net periodic pension cost for the qualified pension plan:

	Three months ended September 30,						Nine months ended September 30,
(In thousands)	2008			2007			2008			2007

Service cost	$	67		$	88		$	221		$	264
Interest cost	124			124			372			372
Expected return on plan assets	(179		)	(180		)	(538		)	(540		)
Amortization of prior service costs	10			11			32			33
Amortization of net actuarial loss	0			6			—			18
Net periodic pension cost	$	22		$	49		$	87		$	147

Postretirement Benefit Obligation

We sponsor a healthcare plan that provides postretirement medical benefits to certain “grandfathered” unionized employees. The plan is contributory, with contributions required at the same rate as active employees. Benefit eligibility under the plan terminates at age 65.

The following table summarizes the components of the net periodic costs for postretirement benefits:

	Three months ended September 30,				Nine months ended September 30,
(In thousands)	2008		2007		2008		2007

Service cost	$	38	$	38	$	114	$	114
Interest cost	34		34		102		102
Net periodic postretirement cost	$	72	$	72	$	216	$	216

(13) Income Taxes

As of September 30, 2008, the Company has no uncertain tax positions outstanding. We include the interest expense or income, as well as potential penalties on unrecognized tax benefits, as components of income tax expense in the Condensed Consolidated Statement of Operations. As of September 30, 2008, because we had no uncertain tax positions outstanding, we also had no liability for accrued interest on unrecognized tax benefits.

Our federal income tax returns for 2006 and 2007 are open for examination under the federal statute of limitations. We file in numerous state and foreign jurisdictions with varying statutes of limitations open from 2003 to 2006.

We have accrued a deferred income tax benefit of $12.3 million related to the $31.6 million realized loss on the sale of auction rate securities for the nine month period ended September 30, 2008. Because we do not expect to have sufficient capital gains to offset the $31.6 million capital loss, we have also recorded a valuation allowance for the full amount of the income tax benefit accrued.

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(14) Earnings (Loss) Per Share

Basic earnings (loss) per share are computed by dividing net income by the weighted average number of common shares outstanding during each period. Diluted earnings (loss) per share are calculated using the treasury stock method in accordance with SFAS 128, and includes the effect of all dilutive securities, including non-qualified stock options and restricted stock units awards (“RSU’s”).

The following table sets forth the computation of basic and diluted earnings (loss) per share:

	Three Months Ended September 30,				Nine months ended September 30,
(In thousands, except per share data)	2008		2007		2008			2007

Net income (loss)	$	2,486	$	2,995	$	(10,227	)	$	30,542

Weighted average shares and share equivalents outstanding:
Basic shares	41,971		41,949		41,927			41,891
Dilutive non-qualified stock options and RSU’s	39		436		31			606
Diluted weighted average shares and share equivalents	42,010		42,385		41,958			42,497

Income (loss) per common share - basic:	$	0.06	$	0.07	$	(0.24	)	$	0.73
Income (loss) per common share - diluted:	$	0.06	$	0.07	$	(0.24	)	$	0.72

We had additional potentially dilutive securities outstanding representing options on 3.9 million common shares at September 30, 2008 that were not included in the computation of potentially dilutive securities because the options exercise prices were greater than the average market price of the common shares or because the options were anti-dilutive, and were excluded from the calculation of diluted earnings per share in accordance with SFAS 128.

(15) Industry Segment

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

(16) Litigation

We are from time to time involved in various legal proceedings, including legal proceedings relating to the extensive environmental laws and regulations that apply to our facilities and operations. We are not involved in any legal proceedings that we believe could have a material adverse effect upon our business, operating results or financial condition.

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 in excess of $31 million as a result of investments in Student Loan Auction Rate Securities purchased through JP Morgan.

(17) Unaudited Condensed Consolidating Financial Information

The following tables present unaudited condensed consolidating financial information for: (a) Aventine Renewable Energy Holdings, Inc. (the “Parent”) on a stand-alone basis; (b) on a combined basis, the guarantors of the 10% senior unsecured Notes (“Subsidiary Guarantors”), which include Aventine Renewable Energy, LLC; Aventine Renewable Energy, Inc.; Aventine Power, LLC; Aventine Renewable Energy – Aurora West, LLC; and Aventine Renewable Energy – Mt. Vernon, LLC; and (c) the Non-Guarantor Subsidiary, Nebraska Energy, LLC. Each Subsidiary Guarantor is wholly-owned by Aventine Renewable Energy Holdings, Inc. The guarantees of each of the Subsidiary Guarantors are full, unconditional, joint and several. Accordingly, separate financial statements of the wholly-owned

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Subsidiary Guarantors are not presented because the Subsidiary Guarantors are jointly, severally and unconditionally liable under the guarantees, and the Company believes that separate financial statements and other disclosures regarding the Subsidiary Guarantors are not material to investors. Furthermore, there are no significant legal restrictions on the Parent’s ability to obtain funds from its subsidiaries by dividend or loan.

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidating Statements of Operations

For the Three Months Ended September 30, 2008

(Unaudited)

(In thousands)	Parent			Subsidiary Guarantors			Non- Guarantor Subsidiary			Eliminations			Consolidated
Net sales	$	—		$	671,525		$	30,581		$	(102,586	)	$	599,520
Cost of goods sold	—			675,663			32,615			(102,288		)	605,990
Gross profit (loss)	—			(4,138		)	(2,034		)	(298		)	(6,470		)
Selling, general and administrative expenses	33			8,338			690			(298		)	8,763
Other (income) expense	—			(409		)	4			—			(405		)
Operating income (loss)	(33		)	(12,067		)	(2,728		)	—			(14,828		)
Other income (expense):
Interest income	—			251			3			—			254
Interest expense	(182		)	(53		)	—			—			(235		)
Equity in undistributed (income) loss of subsidiaries	4,498			(2,000		)	—			(2,498		)	—
Other non-operating income (expense)	—			18,367			—			—			18,367
Minority interest	—			—			—			725			725
Income (loss) before income taxes	4,283			4,498			(2,725		)	(1,773		)	4,283
Income tax expense (benefit)	1,797			1,462			—			(1,462		)	1,797
Net income (loss)	$	2,486		$	3,036		$	(2,725	)	$	(311	)	$	2,486

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidating Statements of Operations

For the Three Months Ended September 30, 2007

(Unaudited)

(In thousands)	Parent			Subsidiary Guarantors			Non- Guarantor Subsidiary			Eliminations			Consolidated
Net sales	$	—		$	353,879		$	20,475		$	(13,680	)	$	360,674
Cost of goods sold	—			357,065			18,863			(13,527		)	362,401
Gross profit (loss)	—			(3,186		)	1,612			(153		)	(1,727		)
Selling, general and administrative expenses	35			8,906			596			(153		)	9,384
Other (income) expense	—			(168		)	(1		)	—			(169		)
Operating income (loss)	(35		)	(11,924		)	1,017			—			(10,942		)
Other income (expense):
Interest income	—			3,546			30			—			3,576
Interest expense	(5,310		)	(49		)	—			—			(5,359		)
Equity in undistributed (income) loss of subsidiaries	(8,436		)	944			—			7,492			—
Other non-operating income (expense)	—			(953		)	—			—			(953		)
Minority interest	—			—			—			(103		)	(103		)
Income before income taxes	(13,781		)	(8,436		)	1,047			7,389			(13,781		)
Income tax expense (benefit)	(16,776		)	(14,591		)	—			14,591			(16,776		)
Net income	$	2,995		$	6,155		$	1,047		$	(7,202	)	$	2,995

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidating Statements of Operations

For the Nine Months Ended September 30, 2008

(Unaudited)

(In thousands)	Parent			Subsidiary Guarantors			Non- Guarantor Subsidiary			Eliminations			Consolidated
Net sales	$	—		$	1,821,514		$	79,895		$	(190,350	)	$	1,711,059
Cost of goods sold	—			1,768,508			81,671			(189,593		)	1,660,586
Gross profit	—			53,006			(1,776		)	(757		)	50,473
Selling, general and administrative expenses	132			26,363			2,033			(757		)	27,771
Loss on the sale of securities	—			31,601			—			—			31,601
Other income	—			(2,835		)	36			—			(2,799		)
Operating income (loss)	(132		)	(2,123		)	(3,845		)	—			(6,100		)
Other income (expense):
Interest income	—			2,981			18			—			2,999
Interest expense	(3,553		)	(198		)	—			—			(3,751		)
Equity in undistributed loss (earnings) of subsidiaries	4,177			(2,597		)	—			(1,580		)	—
Other non-operating income (expense)	—			6,114			—			—			6,114
Minority interest	—			—			—			1,230			1,230
Income (loss) before income taxes	492			4,177			(3,827		)	(350		)	492
Income tax expense (benefit)	10,719			1,358			—			(1,358		)	10,719
Net income (loss)	$	(10,227	)	$	2,819		$	(3,827	)	$	1,008		$	(10,227	)

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidating Statements of Operations

For the Nine Months Ended September 30, 2007

(Unaudited)

(In thousands)	Parent			Subsidiary Guarantors			Non- Guarantor Subsidiary			Eliminations			Consolidated
Net sales	$	—		$	1,185,834		$	69,044		$	(62,628	)	$	1,192,250
Cost of goods sold	—			1,140,836			59,272			(61,975		)	1,138,133
Gross profit	—			44,998			9,772			(653		)	54,117
Selling, general and administrative expenses	271			26,073			2,070			(653		)	27,761
Other income	—			(842		)	(5		)	—			(847		)
Operating loss	(271		)	19,767			7,707			—			27,203
Other income (expense):
Interest income	—			9,024			87			—			9,111
Interest expense	(12,618		)	(98		)	—			—			(12,716		)
Equity in undistributed loss (earnings) of subsidiaries	40,196			6,589			—			(46,785		)	—
Other non-operating income (expense)	—			4,914			141			—			5,055
Minority interest	—			—			—			(1,346		)	(1,346		)
Income (loss) before income taxes	27,307			40,196			7,935			(48,131		)	27,307
Income tax expense (benefit)	(3,235		)	1,214			—			(1,214		)	(3,235		)
Net income (loss)	$	30,542		$	38,982		$	7,935		$	(46,917	)	$	30,542

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidating Balance Sheets

September 30, 2008

(Unaudited)

(In thousands)

Parent

Subsidiary
Guarantors

Non-
Guarantor
Subsidiary

Eliminations

Consolidated

Assets

Current assets

Cash and cash equivalents

—

34,640

1,615

—

36,255

Accounts receivable, net

—

76,954

537

—

77,491

Inventories

—

116,948

2,696

—

119,644

Intercompany receivable

317,832

—

(317,832

)

—

Income tax receivable

—

1,850

—

1,850

Prepaid expenses and other assets

9,213

537

—

9,756

Total current assets

317,838

239,605

5,385

(317,832

)

244,996

Property, plant and equipment, net

—

85,723

17,098

—

102,821

Construction in process

—

442,896

1,787

—

444,683

Investments in subsidiaries

330,542

41,750

—

(372,292

)

—

Other assets

6,183

8,668

—

14,851

Total assets

654,563

818,642

24,270

(690,124

)

807,351

Liabilities and Stockholders’ Equity

Current liabilities

Accounts payable

—

117,605

7,324

—

124,929

Accrued interest

15,000

—

15,000

Accrued liabilities

—

3,781

403

—

4,184

Other current liabilities

—

10,219

230

—

10,449

Intercompany payable

—

317,717

115

(317,832

)

—

Total current liabilities

15,000

449,322

8,072

(317,832

)

154,562

Long-term debt

300,000

—

300,000

Minority interest

—

8,601

Net deferred tax liabilities

—

1,048

—

1,048

Other long-term liabilities

—

3,577

—

3,577

Total liabilities

315,000

453,947

8,072

(309,231

)

467,788

Stockholders’ equity

339,563

364,695

16,198

(380,893

)

339,563

Total liabilities and stockholders’ equity

654,563

818,642

24,270

(690,124

)

807,351

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidating Balance Sheet

December 31, 2007

(In thousands)	Parent		Subsidiary Guarantors		Non-Guarantor Subsidiary		Eliminations			Consolidated
Assets
Current assets
Cash and cash equivalents	$	—	$	13,640	$	3,531	$	—		$	17,171
Short-term investments	—		211,500		—		—			211,500
Accounts receivable, net	—		72,695		363		—			73,058
Inventories	—		80,909		1,705		(1,126		)	81,488
Income tax receivable	—		11,962		—		—			11,962
Intercompany receivable	318,272		—		1,361		(319,633		)	—
Prepaid expenses and other assets	6		12,642		168		—			12,816
Total current assets	318,278		403,348		7,128		(320,759		)	407,995

Property, plant and equipment, net	—		93,001		18,866		—			111,867
Construction in process			225,122		1,288		—			226,410
Investments in subsidiaries	326,365		44,347		—		(370,712		)	—
Net deferred tax assets	—		1,196		—		—			1,196
Other assets	6,728		7,989		—		—			14,717
Total assets	$	651,371	$	775,003	$	27,282	$	(691,471	)	$	762,185

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	—	$	88,675	$	4,322	$	(1,126	)	$	91,871
Accrued interest	7,500		—		—		—			7,500
Accrued liabilities	—		3,361		264		—			3,625
Other current liabilities	—		1,317		305		—			1,622
Intercompany payable	—		319,633		—		(319,633		)	—
Total current liabilities	7,500		412,986		4,891		(320,759		)	104,618

Long-term debt	300,000		—		—		—			300,000
Minority interest	—		—		—		9,832			9,832
Other long-term liabilities	—		3,864		—		—			3,864
Total liabilities	307,500		416,850		4,891		(310,927		)	418,314
Stockholders’ equity	343,871		358,153		22,391		(380,544		)	343,871
Total liabilities and stockholders’ equity	$	651,371	$	775,003	$	27,282	$	(691,471	)	$	762,185

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidating Statement of Cash Flows

For the Nine Months Ended September 30, 2008

(Unaudited)

(In thousands)	Parent			Subsidiary Guarantors			Non- Guarantor Subsidiary			Eliminations		Consolidated

Operating Activities
Net cash provided by (used for) operating activities	$	(1,500	)	$	57,480		$	632		$	—	$	56,612

Investing Activities
Additions to property, plant and equipment	—			(219,419		)	(2,562		)	—		(221,981		)
Sale of investment securities	—			179,900			—					179,900
Indemnification proceeds	—			3,039			—					3,039
Proceeds from the sale of fixed asset	—			—			14					14
Net cash provided by (used for) investing activities	—			(36,480		)	(2,548		)	—		(39,028		)

Financing Activities
Proceeds from issuance of common stock	1,500			—			—			—		1,500
Net cash provided by financing activities	1,500			—			—			—		1,500
Net increase (decrease) in cash and cash equivalents	—			21,000			(1,916		)	—		19,084
Cash and cash equivalents at beginning of period	—			13,640			3,531			—		17,171
Cash and cash equivalents at end of period	$	—		$	34,640		$	1,615		$	—	$	36,255

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidating Statement of Cash Flows

For the Nine Months Ended September 30, 2007

(Unaudited)

(In thousands)	Parent			Subsidiary Guarantors			Non- Guarantor Subsidiary			Eliminations		Consolidated

Operating Activities
Net cash provided by (used for) operating activities	$	(291,297	)	$	334,823		$	10,378		$	—	$	53,904

Investing Activities
Additions to property, plant and equipment	—			(148,023		)	(1,875		)	—		(149,898		)
Investment in short-term securities	—			(183,943		)	—			—		(183,943		)
Net cash used for investing activities	—			(331,966		)	(1,875		)	—		(333,841		)

Financing Activities
Proceeds from issuance of senior unsecured notes	300,000			—			—			—		300,000
Payment of debt issuance costs	(8,220		)	—			—			—		(8,220		)
Proceeds from stock option exercises	508			—			—			—		508
Purchase of Treasury stock	(991		)	—			—			—		(991		)
Distribution to minority stockholders	—			6,273			(8,000		)	—		(1,727		)
Net cash provided by (used for) financing activities	291,297			6,273			(8,000		)	—		289,570
Net increase in cash and cash equivalents	—			9,130			503			—		9,633
Cash and cash equivalents at beginning of period	—			26,413			3,378			—		29,791
Cash and cash equivalents at end of period	$	—		$	35,543		$	3,881		$	—	$	39,424

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(18) Subsequent Event

On October 13, 2008, the Company completed its purchase of the 21.58% of Nebraska Energy, LLC (“NELLC”) that it did not already own from Nebraska Energy Cooperative, Inc. The Company issued 1 million shares of its common stock, with an estimated value of approximately $6.6 million, in exchange for the 21.58% interest. The aggregate value of $6.6 million, or $6.62 per share, was based on the average of Aventine’s closing stock price for the four trading days immediately before the acquisition announcement date, the acquisition announcement date and the four trading days immediately after the acquisition announcement date on July 31, 2008. The purchase will be accounted for under the purchase method of accounting in accordance with the provisions of Statement of Financial Accounting Standards No. 141, “Business Combinations”.

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

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This report contains forward-looking statements made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements include all statements that do not relate solely to current or historical fact, but address events or developments that we anticipate will occur in the future. Forward-looking statements include statements regarding our goals, beliefs, plans or current expectations, taking into account the information currently available to our management. When we use words such as “anticipate,” “intend,” “expect,” “believe,” “plan,” “may,” “should” or “would” or other words that convey uncertainty of future events or outcome, we are making forward-looking statements. Statements relating to future sales, earnings, operating performance, restructuring strategies, plant expansions, capital expenditures and sources and uses of cash, for example, are forward-looking statements.

These forward-looking statements are subject to various risks and uncertainties which could cause actual results to differ materially from those stated or implied by such forward-looking statements. We undertake no obligation to publicly release any revision of any forward-looking statements contained herein to reflect events and circumstances occurring after the date hereof, or to reflect the occurrence of unanticipated events. Information concerning risk factors is contained under Item “1A - Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007 and under Part II, Item 1A of this Quarterly Report on Form 10-Q. You should carefully consider all of the risks and all other information contained in or incorporated by reference in this report and in our filings with the SEC. These risks are not the only ones we face. Additional risks and uncertainties not presently known to us, or which we currently consider immaterial, also may adversely affect us. If any of these risks actually occur, our business, financial condition and results of operations could be materially and adversely affected.

Company Overview

Aventine is a leading producer and marketer of ethanol. Through our own production facilities, marketing alliances with other ethanol producers and our purchase/resale operations, we market and distribute ethanol to many of the leading energy companies in the U.S. We have a comprehensive national distribution network utilizing trucks, a leased railcar and barge fleet and a terminal network at critical points on the nation’s transportation grid where our ethanol is blended with our customers’ gasoline. In addition to producing ethanol, our facilities also produce several co-products including: corn gluten feed and meal, corn germ, condensed corn distillers solubles, dried distillers grain with solubles (“DDGS”), wet distillers grain with solubles (“WDGS”), carbon dioxide and brewers’ yeast.

Results of Operations

The following discussion summarizes the significant factors affecting the consolidated operating results of the Company for the three and nine month periods ended September 30, 2008 and 2007. This discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes to the unaudited condensed consolidated financial statements contained in Item 1 above, and the consolidated financial statements and related notes for the year ended December 31, 2007 included in the Company’s Annual Report on Form 10-K.

Our revenues are principally derived from the sale of ethanol and from the sale of co-products (corn gluten feed and meal, corn germ, condensed corn distillers solubles, DDGS, WDGS, carbon dioxide, and brewers’ yeast) that we produce as by-products during the production of ethanol at our plants, which we refer to as co-product revenues. We sell ethanol obtained from the following sources:

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· Ethanol which we manufacture at our plants;

· Ethanol which we purchase from our marketing alliance partners; and

· Ethanol which we purchase from other producers and marketers.

We market and sell ethanol without regard to whether we produced it, are marketing it for our marketing alliance partners or purchased it for resale from other producers or marketers.

Executive Summary

Net income was $2.5 million, or $0.06 per diluted share in the third quarter of 2008, as compared to net income of $3.0 million, or $0.07 per diluted share, in the third quarter of 2007. Net income in the current quarter decreased primarily as a result of lower commodity spreads and higher conversion costs, offset significantly by realized and unrealized net gains on derivative positions, lower selling, general and administrative costs and larger capitalized interest amounts. Commodity spread, defined as gross ethanol selling price per gallon less net corn cost per gallon, declined from $1.09 per gallon in the third quarter of 2007 to $0.98 per gallon in the third quarter of 2008. The average sales price per gallon of ethanol increased in the third quarter of 2008 to $2.47 per gallon from the $2.01 average received in the third quarter of 2007. However, corn costs during the third quarter of 2008 averaged $5.78 per bushel, significantly higher than our third quarter 2007 cost of $3.81 per bushel. Conversion cost in the third quarter of 2008 was $0.77 per gallon as compared to $0.63 per gallon in the third quarter of 2007.

Gallons of ethanol sold in the third quarter of 2008 increased to a record 226.6 million gallons, as compared to 162.0 million gallons in the third quarter of 2007. The increase resulted from the continued growth of ethanol usage across the country. Ethanol prices significantly below the cost of conventional gasoline provided economic incentives to blenders, in addition to the blenders’ credit, to blend more ethanol. We were able to source and sell additional gallons of ethanol primarily as a result of an increase in the number of gallons available to sell from marketing alliance partners and purchase/resale transactions. Gallons produced during the quarter increased to 47.4 million gallons from 46.8 million gallons in the third quarter of 2007.

The economic impact of selling gallons held in inventory at the end of the second quarter of 2008 with a $2.28 per gallon value as prices decreased during the third quarter of 2008 was a negative impact to cost of goods sold of approximately $7.3 million (including a $4.7 million lower of cost or market adjustment). The average inventory cost of $2.08 per gallon at the end of the third quarter of 2008 versus $2.28 at the end of the second quarter of 2008 reflects the decrease in ethanol prices during the quarter using our weighted average FIFO approach to calculating inventory. Similarly, declining prices throughout the third quarter of 2007 had a negative economic impact on cost of goods sold of $10.6 million.

Our inventory is valued based upon a weighted average price we pay for ethanol that we purchase from our marketing alliance partners and our purchase/resale transactions, along with our own cost to produce ethanol. Changes, either upward or downward, in our purchased cost of ethanol or our own production costs, will cause the inventory value to fluctuate from period to period, perhaps significantly. These changes in value flow through our statement of operations as the inventory is sold and can significantly increase or decrease our profitability.

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short gasoline future positions of $4.8 million, net unrealized gains on CBOT corn positions of $12.3 million and net unrealized gains on short gasoline positions of $10.6 million. All of our derivative positions require cash settlement on a daily basis. Without such cash settlement on the derivative contracts, cash flows from operations would have been significantly lower. Offsetting our short gasoline positions, are forward ethanol sales contracts that are indexed to gasoline. Such contracts are not marked to market. Also not marked to market are forward contracts to purchase corn that are either stand alone, or are taken against short futures positions.

For the Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007

Total gallons of ethanol sold in the third quarter of 2008 increased to 226.6 million gallons, versus 162.0 million gallons sold in the third quarter of 2007. Gallons of ethanol were sourced as follows:

	For the Three Months Ended September 30,
(In thousands, except for percentages)	2008		2007	Increase/ (Decrease)		% Increase/ (Decrease)
Equity production	47,381		46,824	557		1.2	%
Marketing alliance purchases	130,278		84,638	45,640		53.9	%
Purchase/resale	54,495		28,821	25,674		89.1	%
Decrease (increase) in inventory	(5,584	)	1,746	(7,330	)	N.M.	*
Total	226,570		162,029	64,541		39.8	%

* Not meaningful

Net sales in the third quarter of 2008 increased 66.2% from the third quarter of 2007. Net sales were $599.5 million in the third quarter of 2008 versus $360.7 million in the third quarter of 2007. Overall, the increase in net sales was the result of the increase in the number of gallons of ethanol sold and an increase in the average sales price of ethanol sold. Ethanol prices averaged $2.47 per gallon in the third quarter of 2008 versus $2.01 in the third quarter of 2007.

Co-product revenues for the third quarter of 2008 totaled $33.7 million, an increase of $9.7 million or 40.4%, from the third quarter 2007 total of $24.0 million. Co-product revenues increased during the third quarter of 2008 as a result of higher co-product pricing, principally germ, meal, yeast and DDGS caused by the significant increase in corn prices. In the third quarter of 2008, we sold 284.1 thousand tons, versus 284.8 thousand tons in the third quarter of 2007. Co-product revenues, as a percentage of corn costs, were 32.3% during the third quarter of 2008, versus 35.8% in the third quarter of 2007. Co-product revenues, as a percentage of corn costs, decreased in the third quarter of 2008 as compared to 2007 as the result of selling co-products into the spot market in a declining corn environment where we had previously fixed the price on about 63% of our corn in the third quarter.

Cost of goods sold for the quarter ended September 30, 2008 was $606.0 million, compared to $362.4 million for the quarter ended September 30, 2007, an increase of $243.6 million or 67.2%. As a percentage of net sales, cost of goods sold increased to 101.1% from 100.5%. Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from our marketing alliance partners and the cost of purchasing ethanol from other producers and marketers, freight and logistics costs to ship ethanol and co-products, and the cost of motor fuel taxes which have been billed to customers. The increase in cost of goods sold is principally the result of increased corn costs, increased conversion costs, and higher prices paid for purchased ethanol.

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Purchased ethanol in the third quarter of 2008 totaled $419.8 million, versus $214.8 million in the third quarter of 2007. The increase in purchased ethanol resulted from both the increase in the number of gallons of ethanol purchased and from an increase in the cost per gallon of ethanol purchased. In the third quarter of 2008, we purchased 184.8 million gallons of ethanol at an average cost of $2.27 per gallon as compared to 113.5 million gallons of ethanol at an average cost of $1.89 in the third quarter of 2007.

Production costs include corn costs, conversion costs (defined as the cost of converting the corn into ethanol, and includes production salaries, wages and stock-based compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs) and depreciation. Corn costs in the third quarter of 2008 totaled $104.2 million or $5.78 per bushel, versus $67.1 million, or $3.81 per bushel in the third quarter of 2007. Our average corn costs in the third quarter of 2008 were lower than the CBOT average price during the same period. The increase in corn costs is due to higher corn prices as a result of higher input costs, including oil, seed and fertilizer prices, commodity speculation and from increased demand for grains on a global basis, including higher expected demand created by new ethanol production facilities being built.

Conversion costs for the third quarter of 2008 increased to $36.7 million from $29.4 million for the third quarter of 2007. The total dollars spent on conversion costs increased year over year principally as a result of higher utility costs, higher denaturant costs, and higher maintenance costs. The conversion cost per gallon increased year over year to $0.77 per gallon in the third quarter of 2008 versus $0.63 per gallon in the third quarter of 2007.

Depreciation in the third quarter of 2008 totaled $3.4 million, versus $3.3 million in the third quarter of 2007. Motor fuel taxes were $3.8 million in the third quarter of 2008 versus $2.3 million in the third quarter of 2007. The cost of motor fuel taxes are recovered through billings to customers.

Freight/logistics costs were flat year over year on a per gallon basis. Freight/logistics costs in both the third quarter of 2008 and the third quarter of 2007 averaged $0.19 per gallon. Freight/logistics dollars spent increased in the third quarter of 2008 to $44.0 million from $31.0 million in the third quarter of 2007 as a result of more gallons shipped. Freight/logistics cost per gallon is calculated by taking total freight/logistics costs incurred (including costs to ship co-products) and dividing by the total ethanol gallons sold. Although fuel surcharges have begun to ease, freight costs continued to be negatively impacted by such surcharges, and from general freight increases associated with moving product along longer supply lines to emerging new markets in the Southeast.

The average inventory cost of $2.08 per gallon at the end of the third quarter of 2008 versus $2.28 at the end of the second quarter of 2008, using our weighted-average FIFO approach to calculating inventory, reflects declining ethanol prices during the quarter. The economic impact of selling gallons held in inventory at the end of the second quarter of 2008 with a $2.28 per gallon value as prices decreased during the third quarter of 2008 was a negative impact to cost of goods sold of approximately $7.3 million (including a $4.7 million non-cash lower of cost or market adjustment). Similarly, declining prices throughout the third quarter of 2007 negatively impacted cost of goods sold by $10.6 million.

Selling, general & administrative expenses (“SG&A”) were $8.8 million in the third quarter of 2008 as compared to $9.4 million in the third quarter of 2007. The lower expense in the third quarter of 2008 primarily relates to reductions in stock-based compensation expense as a result of changes in forfeiture estimates and the number of performance shares expected to vest totaling $1.2 million. In addition, legal and other outside service fees decreased by $0.6 million.

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Interest income in the third quarter of 2008 was $0.3 million, versus $3.6 million in the third quarter of 2007. The decrease in interest income is due to a lower level of funds available to invest.

Interest expense in the third quarter of 2008 was $0.2 million, as compared to $5.4 million in the third quarter of 2007. Interest expense in the third quarter of 2008 was lower than in the same period in 2007 due to a greater amount of interest being capitalized on our expansion projects during the third quarter of 2008. Interest expense in the third quarter of 2008 included $7.5 million in interest on our $300 million aggregate principal 10.0% senior unsecured notes issued March 27, 2007 and $0.2 million of amortization of deferred financing fees, reduced by capitalized interest of $7.5 million. Interest expense in the third quarter of 2007 included $7.5 million in interest on our $300 million aggregate principal 10.0% senior unsecured notes issued March 27, 2007 and $0.2 million of amortization of deferred financing fees, reduced by capitalized interest of $2.3 million.

Other non-operating income (loss) for the third quarter of 2008 includes $18.4 million of realized and unrealized net gains on derivative contracts, including the effect of marking to market derivative contracts, versus net losses in the third quarter of 2007 of $1.0 million. Derivative gains and losses for the third quarter of 2008 are composed of net realized gains on CBOT corn positions of $0.3 million, net realized losses on short gasoline future positions of $4.8 million, net unrealized gains on CBOT corn positions of $12.3 million and net unrealized gains on short gasoline positions of $10.6 million. All of our derivative positions require cash settlement on a daily basis. Without such cash settlement on the derivative contracts, cash flows from operations would have been significantly lower. Economically offsetting some of our short gasoline positions are forward ethanol sales contracts that are indexed to gasoline. Such contracts are not marked to market. Also not marked to market are below market forward contracts to purchase corn that are either stand-alone, or are economically taken against short futures positions.

The minority interest for the quarter ended September 30, 2008 was a reduction of expense of $0.7 million, compared to a charge to income of $0.1 million for the quarter ended September 30, 2007. This change reflects the reduced operating performance of our Nebraska subsidiary caused primarily by the year over year significant increase in corn costs, and the lower average price received from selling wet distillers grains.

Income tax expense in the third quarter of 2008 totaled $1.8 million. The effective income tax rate in the third quarter of 2008 was 42% of pre-tax income, versus an adjusted income tax rate of approximately 23% in the third quarter of 2007 due to certain FIN 48 adjustments. In 2007, our effective income tax rate was also lower due to the amount of tax free interest received on our investment portfolio.

For the Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

Total gallons of ethanol sold in the first nine months of 2008 increased to 658.1 million gallons, versus 513.9 million gallons sold in the first nine months of 2007. Gallons of ethanol were sourced as follows:

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	For the Nine Months Ended September 30,
(In thousands, except for percentages)	2008		2007	Increase/ (Decrease)		% Increase/ (Decrease)
Equity production	140,706		146,410	(5,704	)	(3.9	)%
Marketing alliance purchases	380,392		294,452	85,940		29.2	%
Purchase/resale	142,603		72,434	70,169		96.9	%
Decrease (increase) in inventory	(5,625	)	652	(6,277	)	N.M.	*
Total	658,076		513,948	144,128		28.0	%

* Not meaningful

Net sales in the first nine months of 2008 increased 43.5% from the same period in 2007. Net sales were $1,711.1 million in the first nine months of 2008 versus $1,192.3 million in the first nine months of 2007. Overall, the increase in net sales was the result of the increase in the number of gallons of ethanol sold and an increase in the average sales price of ethanol sold. Ethanol prices averaged $2.40 per gallon in the first nine months of 2008 versus $2.13 in the first nine months of 2007.

Co-product revenues for the first nine months of 2008 totaled $104.0 million, an increase of $33.7 million or 47.9%, from the first nine months of 2007 total of $70.3 million. Co-product revenues increased during the first nine months of 2008 as a result of higher co-product pricing, principally germ, meal, yeast and DDGS caused by the significant rise in corn prices. In the first nine months of 2008, we sold 829.3 thousand tons, versus 848.9 thousand tons in the first nine months of 2007. Co-product revenues, as a percentage of corn costs, were 37.6% during the first nine months of 2008, versus 34.0% in the first nine months of 2007. Co-product revenues, as a percentage of corn costs, increased in the first nine months of 2008 as compared to 2007 as the result of increases in co-product pricing outpacing our corn costs in 2008 versus 2007. For the first nine months of 2008, our average purchase price per bushel of corn was lower than the CBOT price in effect during the same period.

Cost of goods sold for the first nine months of 2008 was $1,660.6 million, compared to $1,138.1 million for the first nine months of 2007, an increase of $522.5 million or 45.9%. As a percentage of net sales, cost of goods sold increased from 95.5% to 97.1%. Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from our marketing alliance partners and the cost of purchasing ethanol from other producers and marketers, freight and logistics costs to ship ethanol and co-products, and the cost of motor fuel taxes which have been billed to customers. The increase in cost of goods sold is principally the result of increased corn costs, increased conversion costs, and higher prices paid for purchased ethanol.

Purchased ethanol in the first nine months of 2008 totaled $1,155.4 million, versus $722.3 million in the first nine months of 2007. The increase in purchased ethanol results from both the increase in the number of gallons of ethanol purchased and from an increase in the cost per gallon of ethanol purchased. In the first nine months of 2008, we purchased 523.0 million gallons of ethanol at an average cost of $2.21 per gallon as compared to 366.9 million gallons of ethanol at an average cost of $1.97 in the first nine months of 2007.

Production costs include corn costs, conversion costs (defined as the cost of converting the corn into ethanol, and includes production salaries, wages and stock compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs) and depreciation. Corn costs in the first nine months of 2008 totaled $277.1 million or $5.22 per bushel, versus $206.5 million, or $3.79 per bushel in the first nine months of 2007. The increase in corn costs is due to higher corn prices as a result of higher input costs, including oil, seed and fertilizer prices, commodity speculation and from increased demand for grains on

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a global basis, including higher expected demand created by new ethanol production facilities being built.

Conversion costs for the first nine months of 2008 increased to $99.5 million from $87.4 million for the first nine months of 2007. The total dollars spent on conversion costs increased year over year principally as a result of higher utility costs, higher denaturant costs, and higher maintenance costs. The conversion cost per gallon increased year over year to $0.71 per gallon in the first nine months of 2008 versus $0.60 per gallon in the first nine months of 2007. Conversion costs per gallon in the first nine months of 2008 were also negatively affected by the lower number of gallons produced as a result of lowering the denaturant blending levels to 1.96% from 4.76%.

Depreciation in the first nine months of 2008 totaled $10.0 million, versus $9.3 million in the first nine months of 2007. Motor fuel taxes were $11.7 million in the first nine months of 2008 versus $12.8 million in the first nine months of 2007. The cost of motor fuel taxes are recovered through billings to customers.

Freight/logistics costs in the first nine months of 2008 increased to $130.5 million, or approximately $0.20 per gallon, from $89.2 million, or $0.17 per gallon in the first nine months of 2007. Freight/logistics cost per gallon is calculated by taking total freight/logistics costs incurred (including costs to ship co-products) and dividing by the total ethanol gallons sold. The increase in freight costs was primarily due to fuel surcharges resulting from record high oil prices during most of 2008, which negatively impacted general freight rates, and from general freight increases associated with moving product along longer supply lines to emerging new markets in the Southeast. Freight surcharges have now begun to moderate beginning in the third quarter of 2008.

The average inventory cost of $2.08 per gallon at the end of the first nine months of 2008 versus $1.80 at the end of 2007 reflects the increase in ethanol prices using our weighted average FIFO approach to calculating inventory. The economic impact of selling gallons that were previously held in inventory at the end of 2007 during a period of generally rising prices was $10.2 million (this is net of a $4.7 million non-cash lower of cost or market adjustment taken during the third quarter of 2008). Similarly, declining prices throughout the first nine months of 2007 had a negative economic impact on cost of goods sold of $8.6 million.

Selling, general and administrative (“SG&A”) expenses were basically flat year over year at $27.8 million for both the first nine months of 2008 and 2007. Lower stock compensation expense was offset by higher fees for legal and other outside services.

In the first nine months of 2008, the Company incurred losses totaling $31.6 million related to the sale of its portfolio of auction rate securities. The Company holds no auction rate securities as of September 30, 2008.

Interest income in the first nine months of 2008 was $3.0 million, versus $9.1 million in the first nine months of 2007. The decrease in interest income is due to a lower level of funds available to invest, combined with lower interest rates received on the auction rate securities we previously held, many of which reset to zero for most of 2008 during the time period in which they were held.

Interest expense in the first nine months of 2008 was $3.8 million, as compared to $12.7 million in the first nine months of 2007. Interest expense in the first nine months of 2008 was lower than in the same period in 2007 due to a greater amount of interest being capitalized on our expansion projects during 2008. Interest expense in the first nine months of 2008 included $22.5 million in interest on our $300 million aggregate principal 10.0% senior unsecured notes issued March 27, 2007 and $0.8 million

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of amortization of deferred financing fees, reduced by capitalized interest of $19.5 million. Interest expense in the first nine months of 2007 included $15.3 million in interest on our $300 million aggregate principal 10.0% senior unsecured notes issued March 27, 2007 and $0.5 million of amortization of deferred financing fees, reduced by capitalized interest of $3.1 million.

Other non-operating income for the first nine months of 2008 includes $6.1 million of realized and unrealized net gains on derivative contracts, including the effect of marking to market derivative contracts, versus net gains in the first nine months of 2007 of $5.1 million. Derivative gains and losses for the first nine months of 2008 are composed of net realized gains on CBOT corn positions of $7.9 million, net realized losses on short gasoline future positions of $9.3 million, net unrealized gains on CBOT corn positions of $3.9 million and net unrealized gains on short gasoline positions of $3.6 million. All of our derivative positions require cash settlement on a daily basis. Economically offsetting our short gasoline positions are forward ethanol sales contracts that are indexed to gasoline. Such contracts are not marked to market. Also not marked to market are below market forward contracts to purchase corn that are either stand-alone, or are economically taken against short futures positions.

The minority interest for the first nine months of 2008 was a reduction of expense of $1.2 million, compared to a charge to income of $1.3 million for the first nine months of 2007. This change reflects the reduced operating performance of our Nebraska subsidiary caused primarily by the year over year significant increase in corn costs, and the lower average price received from selling wet distillers grains.

Income tax expense in the first nine months of 2008 totaled $10.7 million. The Company does not expect to receive an income tax benefit related to the losses incurred on the sale of auction rate securities as it does not expect to have sufficient capital gains to offset the $31.6 million capital loss. As a result, the Company recorded a valuation allowance equal to the amount of the income tax benefit it recorded resulting from the loss on the sale of auction rate securities. Excluding the effects of the loss on the sale of auction rate securities, the effective income tax rate in the first nine months of 2008 was 33% of pre-tax income, versus an adjusted income tax rate of 23% in the first nine months of 2007. The Company in 2007 recognized a previously unrecognized favorable tax benefit of $9.6 million.

Trends and Factors that May Affect Future Operating Results

Ethanol Pricing

While ethanol pricing increased year to date in 2008 versus 2007, ethanol pricing in the third quarter of 2008 began to decline significantly along with falling oil and other commodity prices, including corn. This decline in ethanol prices during the third quarter of 2008, however, outpaced the decline in corn prices during the same period, thereby producing lower gross margins than had been experienced earlier in 2008. As the supply of ethanol from plants which are currently under construction begins to make its way into the marketplace, we expect ethanol pricing to remain soft, and gross margins to remain near breakeven.

As of September 30, 2008, we had contracts for delivery of ethanol totaling 143.1 million gallons through September 2009. These contracts are shared for the benefit of the marketing alliance pool as a whole, of which Aventine is a part, and are not solely applicable to Aventine. These commitments were for 14.9 million gallons at an average fixed price of $2.26 per gallon, 17.2 million gallons at an average spread to wholesale gasoline of a negative 42 cents per gallon (based upon the NYMEX, Chicago and NY harbor indices), and 111.0 million gallons at spot prices (using various Platt, OPIS and AXXIS indices).

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For the fourth quarter of 2008, we have contracts for delivery of ethanol totaling 137.9 million gallons. These commitments are for 14.9 million gallons at an average fixed price of $2.26, 13.6 million gallons at an average spread to wholesale gasoline of a negative 39 cents (based upon the NYMEX, Chicago and NY harbor indices), and 109.4 million gallons at spot prices (using various Platt, OPIS and AXXIS indices).

At the end of the third quarter of 2008, we also had short gasoline positions outstanding using swap agreements where we sold 3.9 million gallons of gasoline at an average fixed price of $2.06 per gallon for delivery through December 2008. We did this to hedge a portion of our gasoline indexed contracts from potentially falling gasoline prices. The fair value of these positions at September 30, 2008 was a loss of approximately $1.5 million.

Corn

Corn prices have risen significantly since 2006 and reached record levels during the second quarter of 2008. Beginning in the third quarter of 2008, corn prices, along with most other commodities, began to decline in value. We believe that this is in response to larger than expected corn production during 2008, along with concerns of global recession and reductions in global demand. However, 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 CBOT corn futures with similar dates to lock in the basis differential. We also occasionally use 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 September 30, 2008, we had fixed the price of 9.3 million bushels of corn through December 2008 at an average of $5.25 per bushel, representing approximately 39% percent of our corn requirements for the remainder of 2008.

Marketing Alliance

Our marketing alliance annualized volume at the end of the third quarter of 2008 was 639 million gallons. With our own equity production, our marketing alliance partner volumes, and purchase/resale volumes, we distributed approximately 900 million gallons of ethanol on an annualized basis in the third quarter of 2008. Our expectation for the remainder 2008 is that another 215 million gallons of annualized marketing alliance partner production will come online in the fourth quarter. Offsetting this increase in volumes in the fourth quarter will be disruptions in supply from marketing alliance partners as a result of poor industry economics. We have, in the fourth quarter, already seen reductions in production levels and gallons available for distribution from marketing alliance partners and may see additional supply disruptions in the future.

In addition to curtailments in supply from lower production volumes caused by current industry economics, a few existing marketing alliance partners have indicated that they are exploring alternative marketing arrangements. To this end, we have received termination notices from some of our marketing alliance partners for our services.

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Supply and Demand

According to the Renewable Fuels Association, the annual ethanol production capacity in the U.S. of plants currently in operation and those under construction is almost 13.8 billion gallons annually. This volume of ethanol production exceeds the mandate for renewable biofuel consumption required in 2012. Ethanol produced in the United States competes with sugar-based ethanol produced in Brazil. This domestic production capacity, along with imports, may cause supply to exceed demand. If additional demand for ethanol is not created, either through additions to discretionary blending (through increased penetration rates in areas that blend ethanol today or through the establishment of new markets where little or no ethanol is blended today), or through additional state level mandates, the excess supply may cause ethanol prices to decrease, perhaps substantially.

Expansion

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

We may be subject to material penalties if we do not timely complete phase I of the Aurora expansion or either phase of the Mt. Vernon expansion. If phase I of the Aurora plant is not completed and fully operational by July 1, 2009 we will be responsible for liquidated damages to the Aurora Cooperative of $138,889 per month (up to a maximum of $5 million) until the plant is fully operational. If we do not pay these damages, the counterparty has the right to repurchase the property at cost (subject to adjustment for any expenses which we have paid with respect to infrastructure construction). Our lease with the Indiana Port Commission requires substantial completion of phase I of the Mt. Vernon expansion (an initial 110 million gallons of capacity) by March 1, 2009 and substantial completion of phase II of the Mt. Vernon expansion (an additional 110 million gallons of capacity) by January 1, 2011, subject in the case of phase II of the Mt. Vernon expansion to specified extension rights. If we do not achieve these milestones, the State of Indiana may, subject to specified cure rights, take over construction and complete the facility at our expense. In addition, if we fail to achieve these milestones we will, subject to specified cure rights or our ability to negotiate an extension, be in default under our lease and the State of Indiana may also, at its election, (i) without terminating the lease re-let the premises to a third party and charge us for any necessary repairs and alterations, (ii) without terminating the lease, require us to pay all amounts we are obligated to pay under the lease as they become payable, less any amount received from any re-letting of the premises or (iii) terminate the lease. If the State of Indiana terminates the lease it can require that we pay liquidated damages in the amount by which the lease payments we are obligated to make under the lease exceed the fair and reasonable rental value of the premises, each

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discounted to present value (but in no event being less than two years of basic rent and minimum guaranteed wharfage under the lease). In addition, upon any termination or expiration of the lease, the State does not have to pay us for the value of the plant or any other improvements that we made to the premises and can require us to restore the leased premises to their original condition at our cost and expense. In addition, under the design build agreements for the initial 113 million gallon capacity expansion at each of Mt Vernon and Aurora, we have the ability to delay construction by up to 180 days. If we do so, we will be responsible for certain increased costs and foregone profit of the contractor (potentially including an early completion bonus). If we were to delay construction beyond 180 days the contractor would be entitled to treat the delay as a termination by us for convenience and we would be responsible for certain costs and expenses of the contractor in connection with such termination.

Liquidity and Capital Resources

Overview and Outlook

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

(In thousands)	September 30, 2008		December 31, 2007
	(Unaudited)

Cash and cash equivalents	$	36,255	$	17,171
Short-term investments	—		211,500
Working capital	90,434		303,377
Total debt	300,000		300,000
Current ratio	1.59		3.90

The Company has made commitments for the construction of new ethanol facilities. We began construction on the initial phase I expansions in Mt. Vernon, Indiana and Aurora, Nebraska in 2007. It is expected that each phase I project will cost approximately $250 million. Through September 30, 2008, approximately $391.6 million has been spent on these two projects. We expect to spend an additional $109.9 million to complete these projects, excluding capitalized interest.

During the third quarter, the Company amended its engineering, procurement and construction contract for the ethanol facility currently under construction in Aurora, Nebraska. The amendment extends the construction and payment schedules for the ethanol facility. These changes should allow Aventine’s other ethanol facility currently under construction in Mt. Vernon, Indiana to begin producing ethanol and operating cash flows before the Aurora West facility begins production.

Also during the third quarter, we amended our existing five-year secured revolving credit facility to clarify certain ambiguities relating to the treatment of capital expenditures in the calculation of the fixed charge coverage ratio included therein. The amendment changed the definition of “Non-Financed Capital Expenditures” contained in Section 1.01 of facility, which is used in the calculation of the fixed charge coverage ratio. If availability under the facility falls below $50 million, we must maintain a fixed charge coverage ratio of at least 1.1 to 1. At September 30, 2008, we were in compliance with the fixed charge coverage ratio covenant. Based on our current expectations regarding EBITDA and planned capital expenditures, we do not expect to satisfy the fixed charge coverage ratio before the end of 2009 at the earliest and as a result do not expect to be able to access the last $50 million of commitments under the facility. Failing to satisfy the fixed charge ratio does not constitute an event of default nor does it affect our ability to borrow amounts under the facility other than the last $50 million of commitments.

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Total liquidity at September 30, 2008 was $119.2 million, comprised of $36.3 million in cash and cash equivalents and $82.9 million (which is net of the last $50 million which we do not expect to be able to access) under our existing secured revolving credit facility. In early October, we drew down $60 million on our secured revolving credit facility. We have invested these funds in cash equivalents until needed. Proforma cash on hand at September 30, 2008 would have been $96.3 million, including this $60 million borrowing.

We believe that, under current industry conditions, our existing sources of liquidity will be sufficient to enable us to complete and start-up our phase I expansions at Aurora, Nebraska and Mt. Vernon, Indiana. We also expect that our existing sources of liquidity, including cash flows from operations, will be sufficient to allow us to satisfy existing anticipated working capital needs, debt service obligations, capital expenditures and other anticipated cash requirements for 2008. However, we do not expect to have a meaningful amount of excess liquidity to withstand unanticipated liquidity needs. In particular, our inventory, accounts receivable and accounts payable levels can vary materially as a result of changes in commodity prices, particularly corn and ethanol prices, as well as the number of gallons in inventory, the number of gallons of ethanol purchased in purchase resale transactions or from marketing alliance partners and days’ sales outstanding of receivables.

In addition to extending the construction period and pushing out the start-up date for our ethanol facility expansion in Aurora, Nebraska as previously announced, we continue to evaluate a number of other actions designed to increase the amount of liquidity available to us, including; reducing inventory levels, seeking additional debt and equity financing, potentially delaying construction or start-up of our Mt. Vernon, Indiana expansion and other strategic initiatives. We cannot assure you that any of these initiatives will generate additional liquidity for us on acceptable terms or at all.

On October 26, 2006, Aventine’s Board of Directors approved a common stock share buyback program of up to $50 million. Under the repurchase program, the Company may buy back shares from time to time on the open market. The program has no minimum share repurchase amounts, and there is no fixed time period under which any share repurchases must take place. This share repurchase program is not expected to impact the Company’s expansion plans. From program inception through the end of the third quarter of 2008, the Company has repurchased a total of 369,615 shares of its common stock. The amount remaining under the authorization to repurchase stock is approximately $45.9 million. The amounts the Company may repurchase under this program in the future may be affected by cash required to complete current facility expansions, as well as cash provided by operations.

Sources of Liquidity

Our principal sources of liquidity are cash, cash equivalents, short-term investments, cash provided by operations, and cash available under our secured revolving credit facility.

Cash, cash equivalents and short-term investments. For the first nine months of 2008, cash, cash equivalents and short-term investments as a whole decreased by $192.4 million. Cash, cash equivalents and short-term investments as of September 30, 2008 and December 31, 2007 were $36.3 million and $228.7 million, respectively. The decrease in cash, cash equivalents and short-term investments is principally the result of expenditures related to our on-going plant expansion program and losses incurred on the sale of our auction rate security portfolio, all offset by cash provided by our operations.

C ash provided by operations. Net cash provided by operating activities in the first nine months of 2008 was $56.6 million, as compared to cash provided by operating activities of $53.9 million for the first nine months of 2007. Cash provided by operations in 2008 was reduced by a regularly scheduled $15 million semi-annual interest payment made in the second quarter of 2008 on our 10% senior

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unsecured bonds. We issued these bonds in March 2007. As a result, no interest payment on these bonds was required until October 2007.

Cash available under our liquidity facility . In March 2007, we established a new five year secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent and a lender, of up to $200 million, subject to collateral availability, which, under certain circumstances, can be increased to $300 million. See “Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operation - Secured Revolving Credit Facility” below for more information about our secured revolving credit facility.

We had no borrowings outstanding under our secured revolving credit facility at September 30, 2008, and $22.2 million of standby letters of credit outstanding, thereby leaving approximately $132.9 million in borrowing availability under our secured revolving credit facility as of that date (including the $50 million which we have said we do not expect to be able to access).

In early October 2008, we drew down $60 million on our secured revolving credit facility. We have invested these funds in cash equivalents until needed.

Uses of Liquidity

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

Capital expenditures. During the first nine months of 2008, we spent approximately $202.3 million, exclusive of capitalized interest of $19.5 million, on capital projects. Of this amount, $9.0 million was spent on maintenance and environmental projects, while $193.3 million was spent on capacity expansion projects. The amount we expect to spend to complete our two new ethanol production facilities through the second quarter of 2009 is approximately $109.9 million, exclusive of capitalized interest. Expected capital expenditures on non-expansion related maintenance and environmental items should be approximately $1.5 million for the remainder of 2008.

Payments related to our outstanding debt and liquidity facility. In the first nine months of 2008, we made a regularly scheduled $15 million semi-annual payment on our 10% senior unsecured bonds on April 1. Interest payments of $15 million on our 10% senior unsecured notes are due on April 1 and October 1.

Working capital. Our working capital declined from $303.4 million at December 31, 2007 to $90.4 million at September 30, 2008 as we used current assets to fund our capital expenditures.

Secured Revolving Credit Facility

Our liquidity facility consists of a five year secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent and a lender, of up to $200 million, subject to collateral availability, which, under certain circumstances, can be increased up to $300 million. Our secured revolving credit facility includes a $25 million sub-limit for letters of credit. The credit facility expires in March 2012, and, at September 30, 2008, is secured by substantially all of the Company’s assets, with the exception of the assets of Nebraska Energy, LLC.

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of $1.8 million each quarter beginning with the quarter ended December 31, 2007. At September 30, 2008, the amount of property, plant and equipment which was eligible for inclusion in the calculation of the borrowing base was $42.9 million.

Availability under our secured revolving credit facility is subject to customary conditions, including the accuracy of representations and warranties, the absence of any material adverse change and compliance with certain covenants, which, among other things, may limit our ability to incur additional indebtedness and liens; enter into transactions with affiliates; make acquisitions; pay dividends; redeem or repurchase capital stock or senior notes; make investments or loans; consolidate, merge or effect asset sales; or change the nature of our business. In addition, if availability under the facility falls below $50 million, we must maintain a fixed charge coverage ratio of EBITDA (as defined under the agreement) less non-financed capital expenditures and taxes to fixed charges (scheduled payments of principal, interest expense and certain types of dividend and other payments) of at least 1.1 to 1.

As of September 30, 2008, we are in compliance with all covenants under our secured revolving credit facility, including the fixed charge coverage ratio. If we continue with our building expansion on our current timetable and within the expected cost and given our expectations for future EBITDA, we do not expect to be in compliance with the fixed charge coverage ratio covenant before the end of 2009 at the earliest and, therefore, would not have access to the last $50 million of availability. Failing to satisfy the fixed charge ratio does not constitute an event of default nor does it affect our ability to borrow amounts under the facility other than the last $50 million of commitments. We had no borrowings outstanding under our secured revolving credit facility at September 30, 2008, and $22.2 million of standby letters of credit outstanding, thereby leaving approximately $132.9 million in borrowing availability under our secured revolving credit facility as of that date (including the $50 million which we have said we do not expect to be able to access).

Environmental Matters

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

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control equipment. They may also require us to make operational changes to limit actual or potential impacts to the environment. A violation of these laws, regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns. In addition, environmental laws and regulations (and interpretations thereof) change over time, and any such changes, more vigorous enforcement policies or the discovery of currently unknown conditions may require substantial additional environmental expenditures.

We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged for the disposal of hazardous wastes. For instance, soil and groundwater contamination has been identified in the past at our Illinois campus. If any of these sites are subject to investigation and/or remediation requirements, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws for all or part of the costs of such investigation and/or remediation, and for damages to natural resources. We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties. While costs to address contamination or related third-party claims could be significant, based upon currently available information, we are not aware of any material liability relating to contamination or such third party claims. We have not accrued any amounts for environmental matters as of September 30, 2008. The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

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

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

Federal and state environmental authorities have been investigating alleged excess VOC emissions and other air emissions from many U.S. ethanol plants, including our Illinois and Nebraska facilities. The matter relating to our Illinois wet mill facility is still pending, and we could be required to

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install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility. If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred for this matter at our Nebraska facility due to the larger size of the Illinois wet mill facility. In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material. In February 2008, we received an indemnification payment from the former owner of our Nebraska facility relating to the cost of installing environmental controls at that facility in connection with an April 2005 consent decree with state authorities.

We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the U.S. Environmental Protection Agency’s (“EPA”) National Emissions Standard for Hazardous Air Pollutants, or NESHAP, for industrial, commercial and institutional boilers and process heaters. This NESHAP was issued, but subsequently vacated. The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers. We expect the EPA will revise the rule to impose more stringent requirements than were contained in the vacated version. In the absence of a final EPA NESHAP for industrial, commercial and institutional boilers and process heaters, we are working with state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed. We currently cannot estimate the amount that will be needed to comply with any future federal or state technology requirement regarding air emissions from our boilers.

We currently generate revenue from the sale of carbon dioxide, which is a co-product of the ethanol production process at each of our Illinois and Nebraska facilities. New laws or regulations relating to the production, disposal or emissions of carbon dioxide may require us to incur significant additional costs and may also adversely affect our ability to continue generating revenue from carbon dioxide sales. In particular, Illinois and five other Midwestern States have entered into the Midwestern Greenhouse Gas Reduction Accord, a program which directs participating states to develop a multi-sector cap-and-trade mechanism to help achieve reductions in greenhouse gases, including carbon dioxide. It is possible this program could require carbon dioxide emissions reductions from our Pekin, Illinois plants, which could result in significant costs. In addition, it is possible that other states in which we conduct or plan to conduct business, including Nebraska and Indiana, could join this accord or that federal, state or local regulators could require other costly carbon dioxide emissions reductions or offsets.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including changes in commodity prices. Market risk is the potential loss arising from adverse changes in market rates and prices. In the ordinary course of business, we enter into various types of transactions involving financial instruments to manage and reduce the impact of changes in commodity prices. We do not enter into derivatives or other financial instruments for trading or speculative purposes.

Commodity Price Risks

We are subject to market risk with respect to the price and availability of corn, the principal raw material we use to produce ethanol and ethanol by-products. In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions. This is especially true when market conditions do not allow us to pass along increased corn costs to our customers. The availability and price of corn is subject to wide fluctuations due to unpredictable factors such as weather conditions, farmer planting decisions, governmental policies with respect to agriculture and international trade and

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global demand and supply. Our weighted average gross corn costs for the three months ended September 30, 2008 and 2007 was $5.78 and $3.81 per bushel, respectively. For the nine months ended September 30, 2008 and 2007, our weighted average corn costs were $5.22 and $3.79, respectively.

We have firm-price purchase commitments with some of our corn suppliers under which we agree to buy corn at a price set in advance of the actual delivery of that corn to us. At September 30, 2008, we had commitments to purchase approximately 14.7 million bushels of corn through December 2009 at an average price of $5.47 per bushel from these corn suppliers. Under these arrangements, we assume the risk of a price decrease in the market price of corn between the time this price is fixed and the time the corn is delivered. In order to reduce our market exposure to price decreases, at the time we enter into a firm-price purchase commitment, we also often enter into commodity forward contracts to sell a certain amount of corn at the then-current price for delivery to the counterparty at a later date. We account for these commodity forward transactions under Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended by Statement of Financial Accounting Standard No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities , and by Statement of Financial Accounting Standard No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities , (hereinafter collectively referred to as “SFAS 133”). These forward contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative assets is recognized in other current assets in the Condensed Consolidated Balance Sheet, net of any cash received from the brokers. Information on this type of derivative transaction is as follows:

(In millions)	September 30, 2008

Realized and unrealized gain included in earnings in 2008	$	3.8

(In millions)	September 30, 2008

Net bushels sold	5.9
Aggregate notional value of derivatives outstanding	$	34.7
Period through which derivative positions currently exist	December 2009
Unrealized gain on the fair value of outstanding derivative positions	$	5.0
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$	(3.0	)

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

	September 30,
(In millions)	2008

Realized and unrealized net gain included in earnings in 2008	$	8.0

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	September 30,
(In millions)	2008

Net bushels bought	0.1
Aggregate notional value of derivatives outstanding	$	0.4
Period through which derivative positions currently exist	December 2008
Unrealized gain on fair value of derivatives	$	—
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$	—

We are also subject to market risk with respect to ethanol pricing. Our ethanol sales are priced using contracts that can either be fixed; based upon the price of wholesale gasoline plus or minus a fixed amount; or based upon a market price at the time of shipment. These ethanol contracts are for the benefit of our marketing alliance pool. We sometimes fix the price at which we sell ethanol using fixed price physical delivery contracts. These fixed price ethanol contracts are shared with our marketing alliance pool, and are not applicable only to our equity gallons. At September 30, 2008, we had fixed contracts to sell approximately 14.9 million gallons of ethanol at an average fixed price of $2.26 per gallon through December 2008. These normal sale transactions are not marked to market.

We also sell forward ethanol using contracts where the price is determined at a point in the future based upon an index plus or minus a fixed amount. At September 30, 2008, we had sold forward approximately 17.2 million gallons of ethanol using wholesale gasoline as an index plus a fixed spread that averaged a negative $0.42 per gallon. Under these arrangements, we assume the risk of a price decrease in the market price of gasoline. In order to reduce our market exposure to price decreases, at the time we enter into a firm sales commitment, we may also enter into commodity forward contracts to sell a like amount of gasoline at the then-current price for delivery to the counterparty at a later date. These contracts are entered into only to protect the value of our own equity gallons, and are not shared with our marketing alliance. We account for these transactions under SFAS 133. These forward contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative liabilities is recognized in other current liabilities in the Condensed Consolidated Balance Sheet, net of any cash paid to brokers. Information on this type of derivative transaction is as follows:

(In millions)	September 30, 2008

Realized and unrealized loss included in earnings	$	5.7

(In millions)	September 30, 2008

Gallons sold	3.9
Aggregate notional value of derivatives outstanding	$	8.0
Period through which derivative positions currently exist	December 2008
Unrealized loss on the fair value of outstanding derivative positions	$	(1.5	)
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$	(1.0	)

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 factors disclosed.

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

Subsequent Event

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

Based upon evaluation by our management, which was conducted with the participation of Messrs. Miller and Sabherwal, there has been no change in our internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. 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 in excess of $31 million as a result of investments in Student Loan Auction Rate Securities purchased through JP Morgan.

Item 1A. Risk Factors

The Company included in its Annual Report on Form 10-K as of December 31, 2007 a description of certain risks and uncertainties that could affect the Company’s business, future performance or financial condition (“Risk Factors”). The Risk Factors as included in our Form 10-K as of December 31, 2007 are updated by additional risk factors as described below:

Waivers or repeal of the renewable fuels standard (“RFS”) minimum levels of renewable fuels included in gasoline could have a material adverse effect on Aventine’s results of operations.

Subsequent to the passage of the Energy Independence and Security Act of 2007 in December 2007 increasing the mandated required usage of renewable biofuels, there have been several efforts by various parties to repeal or reduce the RFS through new legislation and/or requested waivers of the current legislation. To date, none of these efforts have been successful. However, any repeal or waiver from the RFS may adversely affect demand for ethanol and could have a material adverse effect on Aventine’s results of operations and financial condition.

Our ability to complete our ethanol plant expansion projects in a timely manner and at the expected cost is highly dependant upon third parties, including our engineering, procurement and construction (“EPC”) contractor and their sub-contractors.

We are highly dependant on third parties, including our EPC contractor and their sub-contractors, for the timely completion of our new ethanol production facilities at the expected costs. Delays in the projects, whether the result weather, regulatory issues or other issues related to the EPC contractor or sub-contractor, may affect our results of operations and financial condition.

A reduction in the Volumetric Ethanol Excise Tax Credit (“VEETC”) may reduce the attractiveness of ethanol blended fuels above mandated amounts. Any reduction in the amount of discretionary blending as a result of a reduction in the VEETC may have a material adverse effect on our results of operations and financial condition.

The amount of ethanol production capacity in the U.S. as of September 30, 2008 is approximately 10.5 billion gallons. This amount exceeds the 2008 mandated usage of renewable biofuels of 9 billion gallons. Ethanol consumption above mandated amounts is primarily based upon the economic benefit derived by blenders, including benefits received from the VEETC. The 2008 Farm

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Bill enacted into law reduces the VEETC from its current 51 cents per gallon to 45 cents per gallon beginning in the first year following ethanol production reaching 7.5 billion gallons (which we believe will happen in 2008). Any reduction in discretionary blending as a result of the lower VEETC may affect the demand for ethanol above mandated amounts, thereby having a negative effect on our operations, results of operations and our financial condition.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3. Defaults Upon Senior Securities

None

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

None

Item 5. Other Information

None

Item 6. Exhibits

(a) Exhibits

10.1 Amendment to Engineering, Procurement and Construction Services Fixed Price Contract, dated as of October 6, 2008.

10.2 Letter Agreement dated September 4, 2008 amending the Credit Agreement, dated as of March 23, 2007, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy—Mt Vernon, LLC and Aventine Renewable Energy—Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 17, 2008)

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

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

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

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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.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

	AVENTINE RENEWABLE ENERGY HOLDINGS, INC.


Dated: November 7, 2008	By:	/s/ William J. Brennan
	Name:		William J. Brennan
	Title:		Chief Accounting and Compliance Officer (duly authorized officer and principal accounting officer)

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AVR Aventine Renew Enrgy

- Quarterly Report (10-Q)

07/11/2008 7:46pm

Edgar (US Regulatory)

FORM 10-Q

FORM 10-Q

PART I

PART II

Qualified Retirement Plan

Postretirement Benefit Obligation

SIGNATURE

1 Year Aventine Renew Enrgy Chart

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Aventine Renew Enrgy (AVR) News

AVR Aventine Renew Enrgy

- Quarterly Report (10-Q)

07/11/2008 7:46pm

Edgar (US Regulatory)

FORM 10-Q

FORM 10-Q

PART I

PART II

Qualified Retirement Plan

Postretirement Benefit Obligation

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1 Year Aventine Renew Enrgy Chart

1 Month Aventine Renew Enrgy Chart

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