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, 2007

OR

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

COMMISSION FILE NUMBER 001-32922

AVENTINE RENEWABLE ENERGY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

Delaware		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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer x

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, 2007
Common Stock, $0.001 Par Value		41,982,538 Shares

FORM 10-Q

QUARTERLY REPORT

TABLE OF CONTENTS

		Page No.
	PART I

Item 1.	Financial Statements

	Condensed Consolidated Statements of Operations (Unaudited) — Three and nine month periods ended September 30, 2007 and 2006	1

	Condensed Consolidated Balance Sheets — September 30, 2007 (Unaudited) and December 31, 2006	2

	Condensed Consolidated Statements of Cash Flows (Unaudited) — Nine months ended September 30, 2007 and 2006	3

	Notes to Unaudited Condensed Consolidated Financial Statements	4


Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30

Item 4.	Internal Control Over Financial Reporting	32

Item 4T.	Internal Control Over Financial Reporting	32

PART II

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 3.	Default Upon Senior Securities	33

Item 4.	Submission of Matters to a Vote of Security Holders	33

Item 5.	Other Information	33

Item 6.	Exhibits	34

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

	Three months ended						Nine months ended
	September 30,						September 30,
(In thousands except per share amounts)	2007			2006			2007			2006

Net sales	$	360,674		$	407,053		$	1,192,250		$	1,163,478
Cost of goods sold	362,401			379,708			1,138,133			1,055,330
Gross profit (loss)	(1,727		)	27,345			54,117			108,148
Selling, general and administrative expenses	9,384			7,385			27,761			21,023
Other (income)	(169		)	(616		)	(847		)	(1,223		)
Operating income (loss)	(10,942		)	20,576			27,203			88,348
Other income (expense):
Interest income	3,576			1,449			9,111			3,333
Interest expense	(5,359		)	(747		)	(12,716		)	(9,348		)
Loss on early extinguishment of debt	—			(14,448		)	—			(14,448		)
Other non-operating income (loss)	(953		)	2,348			5,055			4,802
Minority interest	(103		)	(876		)	(1,346		)	(3,793		)
Income (loss) before income taxes	(13,781		)	8,302			27,307			68,894
Income tax expense (benefit)	(16,776		)	3,015			(3,235		)	26,766
Net income	$	2,995		$	5,287		30,542			$	42,128

Per share data:
Income per common share — basic:	$	0.07		$	0.13		$	0.73		$	1.13
Basic weighted average number of common shares	41,949			41,541			41,891			37,279

Income per common share — diluted:	$	0.07		$	0.12		$	0.72		$	1.09
Diluted weighted average number of common and common equivalent shares	42,385			42,691			42,497			38,581

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

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(In thousands except share amounts)	September 30, 2007 (Unaudited)			December 31, 2006

Assets
Current assets
Cash and cash equivalents	$	39,424		$	29,791
Short-term investments	282,868			98,925
Accounts receivable	47,800			79,729
Inventories	60,787			67,051
Income tax receivable	14,186			6,446
Prepaid expenses and other	5,795			4,549
Total current assets	450,860			286,491

Property, plant and equipment, net	111,602			40,962
Construction in process	144,634			74,683
Net deferred tax asset	2,109			—
Other assets	13,762			6,000
Total assets	$	722,967		$	408,136

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	48,207		$	77,442
Accrued liabilities	3,952			3,679
Accrued interest payable	15,333			—
Other current liabilities	1,771			2,123
Total current liabilities	69,263			83,244

Senior unsecured 10% notes due April 2017	300,000			—
Minority interest	9,840			10,221
Net deferred tax liability	—			6,104
Other long-term liabilities	3,971			4,404
Total liabilities	383,074			103,973

Stockholders’ equity
Common stock, par value $0.001 per share; 185,000,000 shares authorized; 41,972,538 and 41,782,276 shares issued and outstanding as of September 30, 2007 and December 31, 2006, respectively, net of 21,300,325 shares held in treasury as of September 30, 2007 and 21,229,025 shares held in treasury as of December 31, 2006	42			42
Preferred stock, 50,000,000 shares authorized, no shares issued or outstanding	—			—
Additional paid-in capital	279,222			274,307
Retained earnings	61,678			30,888
Accumulated other comprehensive loss	(1,049		)	(1,074		)
Total stockholders’ equity	339,893			304,163
Total liabilities and stockholders’ equity	$	722,967		$	408,136

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

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine months ended September 30,
(In thousands)	2007			2006

Operating Activities
Net income	$	30,542		$	42,128
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	9,765			3,529
Lower of cost or market adjustment related to inventory	1,600			—
Loss on early extinguishment of debt	—			14,448
Minority interest	1,346			3,793
Stock-based compensation expense	5,258			5,669
Deferred income tax	(7,939		)	(359		)
Other	—			838
Changes in operating assets and liabilities:
Accounts receivable, net	31,929			(10,082		)
Inventories	4,664			(36,669		)
Accounts payable	(29,235		)	6,663
Other changes in operating assets and liabilities	5,835			(8,275		)
Net cash provided by operating activities	53,765			21,683

Investing Activities
Additions to property, plant and equipment, net	(149,898		)	(51,981		)
Investment in short-term securities	(183,943		)	(90,925		)
Increase in restricted cash for investing activities	—			(1,257		)
Release of restricted cash	—			29,762
Use of restricted cash for plant expansion	—			31,857
Net cash used for investing activities	(333,841		)	(82,544		)

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			221
Tax benefit of stock option exercises	139			4,034
Repayment of senior secured notes, including premium	—			(163,618		)
Net proceeds from the sale of common stock	—			260,915
Net repayments on revolving credit facilities	—			(1,514		)
Distributions to minority shareholders	(1,727		)	(2,590		)
Net cash provided by financing activities	289,709			97,448
Net increase in cash and cash equivalents	9,633			36,587
Cash and cash equivalents at beginning of period	29,791			3,750
Cash and cash equivalents at end of period	$	39,424		$	40,337

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

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, 2006.

The accompanying 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, 2007 and 2006. 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, 2007, the Company’s Summary of Critical Accounting Policies for the year ended December 31, 2006, which are detailed in the Company’s Annual Report on Form 10-K, have not changed from December 31, 2006, except for the adoption of Financial Accounting Standards Board (“FASB”) Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes. See Note 12 for additional information regarding the adoption of FIN 48 by the Company.

(2) Recent Accounting Pronouncements

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (“SFAS 157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the effect that the adoption of SFAS 157 will have, if any, on its consolidated results of operations, financial position and related disclosures.

In February 2007, The FASB issued Statement of Financial Accounting Standards No. 159 (“SFAS 159”), The Fair Value Option for Financial Assets and Financial Liabilities Including an amendment of FASB Statement No. 115. SFAS No. 159 permits a company to choose to measure many financial instruments and other items at fair value that are not currently required to be measured at fair value. The objective is to improve financial reporting by providing a company with the opportunity to

mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. A company shall report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. SFAS No. 159 will be effective for fiscal years that begin after November 15, 2007. We are currently assessing the impact SFAS No. 159 will have on our consolidated financial statements.

In June 2007, the FASB ratified the consensus on Emerging Issues Task Force (“EITF”) Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (“EITF 06-11”). EITF 06-11 requires companies to recognize the income tax benefit realized from dividends or dividend equivalents that are charged to retained earnings and paid to employees for non-vested equity-classified employee share-based payment awards as an increase to additional paid-in capital. EITF 06-11 is effective for fiscal years beginning after September 15, 2007. While we are currently evaluating the provisions of EITF 06-11, the adoption is not expected to have any significant effect on our consolidated financial position or results of operations.

(3) Short-Term Securities

We from time to time invest a portion of our cash in tax-free municipal auction rate certificates which generally have contractual maturities of greater than 20 years. We consider these certificates as held for sale. These certificates are widely traded in the public markets and may be sold as needed. The interest rates on these certificates reprice every 35 days to the then current market rate. Generally, the carrying value of these securities approximates the market value, and there is no gain or loss expected from changes in market value.

(4) Inventories

Inventories are as follows:

(In thousands)	September 30, 2007			December 31, 2006
Finished products	$		53,967	$	61,775
Work-in-process	2,228			1,106
Raw materials	2,572			2,070
Supplies	2,020			2,100
Totals	$	60,787		$		67,051

In the third quarter of 2007, we reduced the value of our inventory for finished ethanol by $1.6 million to reflect a lower of cost or market adjustment.

(5) Prepaid Expenses and Other

Prepaid expenses and other are as follows:

(In thousands)	September 30, 2007		December 31, 2006
Fair value of derivative instruments	$	2,248	$	1,503
Prepaid insurance	1,850		1,280
Deferred income taxes current	1,025		1,064
Other prepaid expenses	672		702
Totals	$	5,795	$	4,549

(6) Other Assets

Other assets are as follows:

(In thousands)	September 30, 2007			December 31, 2006
Deferred debt issuance costs	$		7,762	$	—
Investment in marketing alliances	6,000			6,000
Totals	$	13,762		$		6,000

(7) Debt

The following table summarizes long-term debt:

(In thousands)	September 30, 2007			December 31, 2006
Senior unsecured 10% notes due April 2017	$		300,000	$	—
Secured revolving credit facility	—			—
	300,000			—
Less short-term borrowings	—			—
Total	$	300,000		$		—

Liquidity Facility

In March 2007, we entered into a new secured revolving credit facility with JPMorgan Chase Bank, N.A. of up to $200 million, subject to collateral availability, which, under certain circumstances, can be increased up to $300 million. Collateral availability is determined via a borrowing base, which includes a percentage of eligible receivables and inventory, and $50 million of property, plant and equipment. We had no borrowings outstanding under our secured revolving credit facility at September 30, 2007, and $1.5 million of standby letters of credit outstanding, thereby leaving approximately $116.2 million in additional borrowing availability under our secured revolving credit facility as of that date. A fixed asset component in the amount of $50 million was added to the borrowing base during the quarter ended September 30, 2007.

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.

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.

(8) Other Long-Term Liabilities

Other long-term liabilities are as follows:

(In thousands)	September 30, 2007		December 31, 2006
Accrued pension and postretirement	$	2,311	$	2,427
Unearned commissions	1,660		1,977
Totals	$	3,971	$	4,404

(9) 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 this 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 no long-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 are estimated using a 3% forfeiture rate. The expected option term is calculated using the “simplified” method permitted by Staff Accounting Bulletin No. 107. Our options have characteristics significantly different from those of traded options, and changes in the assumptions can materially affect the fair value estimates.

Beginning in 2007, the Company commenced an ongoing long-term incentive program under the Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan, as amended (the “Plan”). It is anticipated that this program will provide regular annual grants of performance shares. Performance shares are stock units that will be converted to common shares, to the extent earned, at the end of a three-year performance cycle. The first performance cycle began on January 1, 2007, and will end on December 31, 2009. Under the performance share program, each participant is given a target award expressed as a number of shares, with a payout opportunity ranging from 0% to 150% of the target, depending on the performance relative to pre-determined goals. The performance goals for the January

1, 2007 to December 31, 2009 performance cycle relate to the growth of the Company as measured by actual equity gallons produced. On May 25, 2007, the Company issued 94,500 performance shares at the target award level to various participants under the Plan. Under FAS 123R, an accounting estimate of the number of these shares that are expected to vest has been made and are being expensed utilizing the grant-date fair value of the shares from the date of grant through the end of the performance cycle period. Any future changes to the estimate will be reflected in stock-based compensation expense in the period the estimate change is made.

Pre-tax stock-based compensation expense for the three month period ended September 30, 2007 was $1.9 million, of which $0.1 million was charged to cost of goods sold and $1.8 million was charged to selling, general and administrative expense. This expense reduced earnings per share by $0.03 per basic and diluted share for the quarter ended September 30, 2007. For the three month period ended September 30, 2006, pre-tax stock-based compensation expense was $2.6 million, of which $0.1 million was charged to cost of goods sold and $2.5 million was charged to selling, general and administrative expense. This expense reduced earnings per share by $0.04 per basic and diluted share for the quarter ended September 30, 2006. For the nine month period ended September 30, 2007, pre-tax stock-based compensation expense was $5.3 million, of which $0.1 million was charged to cost of goods sold and $5.2 million was charged to selling, general and administrative expense. This expense reduced earnings per share for the nine month period ended September 30, 2007 by $0.08 per basic and diluted share. For the nine month period ended September 30, 2006, pre-tax stock-based compensation expense was $5.7 million, of which $0.1 million was charged to cost of goods sold and $5.6 million was charged to selling, general and administrative expense. This expense reduced earnings per share for the nine month period ended September 30, 2006 by $0.09 per basic and diluted share. The Company recognized a tax benefit on its condensed consolidated statement of income from stock-based compensation expense in the amount of $0.7 million and $1.0 million for the three month periods ended September 30, 2007 and 2006, respectively, and in the amount of $2.1 million and $2.2 million for the nine month periods ended September 30, 2007 and 2006, respectively. The Company recorded pre-tax stock-based compensation expense for the three and nine month periods ended September 30, 2007 and 2006 as follows:

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2007		2006		2007		2006
Stock-based compensation expense:
Non-qualified stock options	$	1.7	$	2.6	$	4.8	$	5.6
Restricted stock	0.1		—		0.3		0.1
Restricted stock units	—		—		0.1		—
Long-term incentive stock plan	0.1		—		0.1		—

As of September 30, 2007 and 2006, the Company had not yet recognized compensation expense on the following non-vested awards:

	2007			2006
(in millions)	Non-recognized Compensation		Weighted Average Remaining Recognition Period (years)	Non-recognized Compensation		Weighted Average Remaining Recognition Period (years)
Non-qualified options	$	19.6	2.4	$	21.7	3.1
Restricted stock	1.1		4.1	0.2		2.6
Restricted stock units	0.2		1.0	—		—
Long-term incentive stock plan	1.4		1.7	—		—
Total	$	22.3	2.4	$	21.9	3.1

The Company granted stock options during the quarters ended September 30, 2007 and 2006. 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 three month periods ended September 30, 2007 and 2006. 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. Assumptions for options granted in the three month period ending September 30, 2007 and 2006 are as follows:

	2007			2006
Expected stock price volatility	58.0		%	58.0		%
Expected life (in years)	6.5			6.5
Risk-free interest rate	4.92		%	5.2		%
Expected dividend yield	0.0		%	0.0		%
Weighted average fair value	$	9.97		$	26.47

The following table summarizes stock options outstanding and changes during the nine month period ended September 30, 2007:

	Shares (in thousands)		Weighted Average Exercise Price		Weighted Average Remaining Life (years)	Aggregate Intrinsic Value (in thousands)
Options outstanding — January 1, 2007	3,265		$	6.57	8.1	$	—
Granted	480		16.00		9.6	—
Exercised	(191	)	2.66		—	—
Cancelled or expired	(28	)	4.35		—	—
Options outstanding — September 30, 2007	3,526		$	8.08	7.6	$	8,780
Options exercisable — September 30, 2007	1,138		$	3.58	6.6	$	7,955

The range of exercise prices of the exercisable options and outstanding options at September 30, 2007 are as follows:

Weighted Average Exercise Price	Number of Exercisable Options (in thousands)	Number of Outstanding Options (in thousands)	Weighted Average Remaining Life (years)
$0.23	696	1,016	5.8
$2.36 - $2.92	285	744	7.7
$4.35	31	616	8.0
$15.26 - $17.29	—	480	9.6
$22.15 - $22.50	118	630	8.5
$43.00	8	40	8.8
Totals	1,138	3,526	7.6

Restricted stock award activity for the nine months ended September 30, 2007 is summarized below:

	Shares (in thousands)	Weighted Average Grant Date Fair Value per Award
Unvested restricted stock awards — January 1, 2007	8.1	$	27.92
Granted	74.7	15.54
Vested	2.7	27.92
Cancelled or expired	—	—
Unvested restricted stock awards — September 30, 2007	80.1	$	16.74

Restricted stock units represent the right to receive a share of stock in the future, provided that the restrictions and conditions designated have been satisfied. Restricted stock unit award activity for the nine months ended September 30, 2007 is summarized below:

	Shares (in thousands)	Weighted Average Grant Date Fair Value per Award
Unvested Restricted stock unit awards — January 1, 2007	—	$	—
Granted	18.0	$	15.85
Vested	—	—
Cancelled or expired	—	—
Restricted stock unit awards — September 30, 2007	18.0	$	15.85

(10) Interest Expense

The following table summarizes interest expense:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2007			2006			2007			2006
Interest expense	$	7,500		$	989		$	15,336		$	10,351
Amortization of deferred debt issuance costs	229			—			458			—
Capitalized interest	(2,370		)	(242		)	(3,078		)	(1,003		)
Interest expense, net	$	5,359		$	747		$	12,716		$	9,348

(11) Pension Expense

Defined Contribution Plans

We have 401(k) plans covering substantially all of our employees. We recorded expense with respect to these plans for the three month periods ended September 30, 2007 and 2006 of $0.2 million and $0.3 million, respectively, and expense of $0.9 million for the nine month periods ended September 30, 2007 and 2006. Contributions made under our defined contribution plans include a match, at the Company’s discretion, of employee contributions to the plans.

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)	2007			2006			2007			2006
Service cost	$	88		$	71		$	264		$	214
Interest cost	124			107			372			322
Expected return on plan assets	(180		)	(128		)	(540		)	(384		)
Amortization of prior service costs	11			—			33			—
Amortization of net actuarial loss	6			12			18			36
Net periodic pension cost	$	49		$	62		$	147		$	188

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)	2007		2006		2007		2006
Service cost	$	38	$	38	$	114	$	114
Interest cost	34		30		102		91
Amortization of prior service cost	—		3		—		8
Net periodic postretirement cost	$	72	$	71	$	216	$	213

(12) Income Taxes

Our federal income tax returns covering fiscal years 2004 and 2005 had been under audit by the Internal Revenue Service (“IRS”). The audit was completed in September 2007. As a result, the Company was able to finalize positions relating to certain tax matters which previously required liability recognition under FIN 48 as discussed below. The Company recognized in the third quarter of 2007 a previously unrecorded favorable tax benefit of $9.6 million, which includes its previously recorded liability for uncertain tax benefits, the related interest and the release of code section 382 valuation allowances.

In July 2006, the FASB issued FIN 48. This interpretation clarified the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure.

We adopted the provisions of FIN 48 on January 1, 2007. As a result of the adoption, we recognized a $0.7 million decrease in our reserves for uncertain tax positions and a $0.5 million increase in accrued interest on uncertain tax positions, resulting in a net $0.2 million increase in retained earnings. We also reclassified $8.1 million between deferred income taxes and other long-term liabilities to conform to the balance sheet presentation requirements of FIN 48. As of January 1, 2007, we had $8.5 million of uncertain tax benefits. As of September 30, 2007, the Company has no uncertain tax positions outstanding.

We included the interest expense or income, as well as potential penalties on unrecognized tax benefits, as components of income tax expense in the condensed consolidated statement of operations. The total amount of accrued interest related to uncertain tax positions at January 1, 2007 was $0.5 million, net of the deferred tax benefit, and was previously included in other long-term liabilities. As of September 30, 2007, because we had no uncertain tax positions outstanding, we also had no liability for accrued interest on unrecognized tax benefits.

The Company’s estimated annual tax rate for 2007, exclusive of the FIN 48 adjustment discussed above which resulted from concluding the recent IRS examination, is 23.4%. The difference between the Company's estimated annual tax rate of 23.4% and the statutory rate is primarily the result of significant amounts of tax-exempt interest income.

(13) Earnings per Share

Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding during each period. Diluted earnings 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 (“RSU’s”).

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

	Three Months Ended September 30,				Nine months ended September 30,
(In thousands, except per share data)	2007		2006		2007		2006
Net income	$	2,995	$	5,287	$	30,542	$	42,128

Weighted average shares and share equivalents outstanding:
Basic shares	41,949		41,541		41,891		37,279
Dilutive non-qualified stock options and RSU’s	436		1,150		606		1,302
Diluted weighted average shares and share equivalents	42,385		42,691		42,497		38,581

Income per common share — basic:	$	0.07	$	0.13	$	0.73	$	1.13
Income per common share — diluted:	$	0.07	$	0.12	$	0.72	$	1.09

We had additional potential dilutive securities outstanding representing 1.2 million common shares that were not included in the computation of potentially dilutive securities for the quarter ended September 30, 2007 because the options’ exercise prices were greater than the average market price of the common shares.

(14) Industry Segment

The Company operates in one reportable business segment, the manufacture and marketing of biofuels.

(15) 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.

(16) Condensed Consolidating Financial Information

The following tables present 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 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, 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 expense (income)	—			(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		)
Investment in subsidiaries	(8,436		)	944			—			7,492			—
Other non-operating income (expense)	—			(953		)	—			—			(953		)
Minority interest	—			—			—			(103		)	(103		)
Income/(loss) 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

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 expense (income)	—			(842		)	(5		)	—			(847		)
Operating income (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		)
Investment in subsidiaries	40,196			6,589			—			(46,785		)	—
Other non-operating income (expense)	—			4,914			141			—			5,055
Minority interest	—			—			—			(1,346		)	(1,346		)
Income 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	$	30,542		$	38,982		$	7,935		$	(46,917	)	$	30,542

Aventine Renewable Energy Holdings, Inc. and Subsidiaries
Condensed Consolidating Balance Sheet
September 30, 2007
(Unaudited)

(In thousands)	Parent		Subsidiary Guarantors				Non-Guarantor Subsidiary			Eliminations				Consolidated
Assets
Current assets
Cash and cash equivalents	$	—	$		35,543		$	3,881		$				$	39,424
Short-term investments	—		282,868				—							282,868
Accounts receivable, net	—		47,364				436							47,800
Inventories	—		59,241				1,546							60,787
Income tax receivable	—		14,186				—							14,186
Intercompany receivable	331,465		—				527			(331,992			)	—
Other assets	6		5,554				235							5,795
Total current assets	331,471		444,756				6,625			(331,992			)	450,860

Property, plant and equipment, net	—		236,545				19,691							256,236
Investment in subsidiaries	316,845		43,814				—			(360,659			)	—
Net deferred tax assets	—		2,109				—							2,109
Other assets	6,910		6,852				—							13,762
Total assets	$	655,226	$			734,076	$	26,316		$	(692,651		)	$	722,967

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	—	$			44,201	$	4,006		$	—			$	48,207
Accrued liabilities	—		3,590				362			—				3,952
Other current liabilities	15,333		1,689				82			—				17,104
Intercompany payable	—		331,992				—			(331,992			)	—
Total current liabilities	15,333		381,472				4,450			(331,992			)	69,263

Long-term debt	300,000		—				—							300,000
Minority interest	—		—				—			9,840				9,840
Other long-term liabilities	—		3,971				—							3,971
Total liabilities	315,333		385,443				4,450			(322,152			)	383,074
Stockholders’ equity	339,893		348,633				21,866			(370,499			)	339,893
Total liabilities and stockholders’ equity	$	655,226	$	734,076			$		26,316	$		(692,651	)	$		722,967

Aventine Renewable Energy Holdings, Inc. and Subsidiaries
Condensed Consolidating Statements 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	$	(291,436	)	$	334,823		$	10,378		$	—	$	53,765
										—
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		)
Repurchase of common stock	(991		)									(991		)
Proceeds from stock option exercises	508			—			—			—		508
Tax benefit of stock option exercises	139			—			—			—		139
Distribution to minority stockholders	—			6,273			(8,000		)	—		(1,727		)
Net cash provided by (used for) financing activities	291,436			6,273			(8,000		)	—		289,709
Net increase/(decrease) 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

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, 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 year ended December 31, 2006. 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. Aventine is also a marketer and distributor of biodiesel. 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, 2007 and 2006. 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, 2006 included in the Company’s Annual Report on Form 10-K.

Our revenues are principally derived from the sale of biofuels 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 biofuels obtained from the following sources:

• Ethanol which we manufacture at our plants;

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

• Ethanol and bio-diesel that 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. In addition to ethanol, we also purchase and market biodiesel.

Executive Summary

We generated net income of $3.0 million, or $0.07 per diluted share in the third quarter of 2007, as compared to net income of $5.3 million, or $0.12 per diluted share, in the third quarter of 2006. Net income decreased primarily as a result of significantly lower ethanol revenue per gallon sold, along with higher corn costs, partially offset by $9.6 million of previously unrecognized income tax benefits. In addition, higher selling, general and administrative expenses, including costs associated with being a public company and from the expansion and growth of our business, also attributed to the decline in net earnings. Revenue in the third quarter of 2007 was $360.7 million, a decrease of $46.4 million, or 11.4%, from third quarter 2006 revenue of $407.1 million. The decrease is mainly the result of a decrease in the average price per gallon of ethanol sold. The average sales price per gallon of ethanol in the third quarter of 2007 was $2.01 per gallon, down from $2.37 per gallon in the same quarter in 2006.

Gallons of ethanol sold in the third quarter of 2007 were flat compared to the third quarter of 2006. Gallons sold in the third quarter of 2007 totaled 162.0 million gallons, as compared to 163.3 million gallons in the third quarter of 2006. Higher equity production related to the new Pekin dry mill was offset by a reduction in marketing alliance gallons purchased. Ethanol purchased from other producers and marketers was also higher in the third quarter of 2007 versus 2006. Ethanol production in the quarter totaled 46.8 million gallons, up from 32.1 million gallons in the third quarter of 2006.

Gross profit was a negative $1.7 million in the third quarter of 2007, a decrease of $29.0 million from the third quarter of 2006. The decline in gross profit was principally the result of a significantly lower commodity spread (defined as the gross ethanol selling price per gallon of ethanol less net corn cost per gallon) caused by lower ethanol prices and, to a lesser extent, higher corn prices. Every 1 cent decline in ethanol prices requires a 4 cent decline in corn prices to maintain the same spread. Our corn costs during the third quarter of 2007 averaged $3.81 per bushel, significantly higher than our third quarter 2006 cost of $2.31 per bushel.

The average inventory cost of $1.61 per gallon at the end of the the third quarter of 2007 versus $1.98 at the end of the second quarter of 2007 reflects the sharp decline in ethanol prices during the quarter 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 the second quarter of 2007 during a period of declining prices, was $9.0 million. Such decline in value was further affected by a $1.6 million non-cash lower of cost or market adjustment. The economic impact of this same issue in the third quarter of 2006 was a negative $10.5 million, as the third quarter of 2006 average cost of inventory was $1.94 per gallon as compared to $2.19 per gallon at the end of the second quarter of 2006. Our inventory is valued based upon a weighted average price we pay for ethanol that we purchase from our marketing alliance partners and our purchase/resale transactions, along with our own cost to produce ethanol. Changes, either upward or downward, in our purchased cost of ethanol or our own production costs, will cause the inventory value to fluctuate from period to period, perhaps significantly. These changes in

value flow through our statement of operations as the inventory is sold and can significantly increase or decrease our profitability.

Other non-operating expense for the third quarter of 2007 includes $1.0 million of realized and unrealized gains on corn derivative contracts and realized and unrealized losses on the sale of forward gasoline contracts. All of our derivative hedge positions have been marked to market, and we have already recorded income or loss with respect to these positions as of September 30, 2007. Increases in prices for open derivative contracts above the closing price at September 30, 2007 will result in mark to market losses on these positions in future periods, while prices lower than those at September 30, 2007 will allow for additional hedge gains.

For the Three Months Ended September 30, 2007 Compared to the Three Months Ended September 30, 2006

Total gallons of ethanol sold in the third quarter of 2007 were flat at 162.0 million gallons, versus 163.3 million gallons sold in the third quarter of 2006. Gallons of ethanol were sourced as follows:

	For the Three Months Ended September 30,
(In thousands, except for percentages)	2007	2006		Increase/ (Decrease)		% Increase/ (Decrease)
Equity production	46,824	32,099		14,725		45.9	%
Marketing alliance purchases	84,638	124,382		(39,744	)	(32.0	%)
Purchase/resale	28,821	18,314		10,507		57.4	%
Decrease/(increase) in inventory	1,746	(11,454	)	13,200		N.M.	*
Total	162,029	163,341		(1,312	)	(0.8	%)

* Not meaningful

Net sales in the third quarter of 2007 decreased 11.4% from the third quarter of 2006. Net sales were $360.7 million in the third quarter of 2007 versus $407.1 million in the third quarter of 2006. Overall, the decrease in net sales was the result of a decrease in the average sales price of ethanol sold. Ethanol prices averaged $2.01 per gallon in the third quarter of 2007 versus $2.37 in the third quarter of 2006.

Co-product revenue for the third quarter of 2007 totaled $24.0 million, an increase of $10.3 million or 75.2%, from the third quarter 2006 total of $13.7 million. Co-product revenue increased during the third quarter of 2007 as a result of a combination of increased co-product tonnage sold as a result of the DDGS produced from the new Pekin dry mill production and higher average selling prices for germ, meal and yeast. In the third quarter of 2007, we sold 284.8 thousand tons, versus 233.1 thousand tons in the third quarter of 2006. Co-product revenues, as a percentage of corn costs, were 35.8% during the third quarter of 2007, versus 47.1% in the third quarter of 2006. Co-product revenues, as a percentage of corn costs, decreased in the third quarter of 2007 as compared to 2006 as the result of the mix of co-products produced. Due to the addition of the new dry mill in Pekin, the increase in DDGS production increased the percentage of the lower value DDGS to the overall mix of available co-products.

Cost of goods sold for the quarter ended September 30, 2007 was $362.4 million, compared to $379.7 million for the quarter ended September 30, 2006, a decrease of $17.3 million or 4.6%. 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 and biodiesel from other producers and marketers, freight and logistics costs to ship ethanol, bio-diesel and co-products, and the

cost of motor fuel taxes which have been billed to customers. The decrease in cost of goods sold is principally the result of the reduced number of ethanol gallons purchased from marketing alliance partners, offset by higher corn and production costs.

Purchased ethanol in the third quarter of 2007 totaled $214.8 million, versus $315.3 million in the third quarter of 2006. The decrease in purchased ethanol results from both a decrease in the number of gallons of ethanol purchased, and by decreases in the cost per gallon of ethanol purchased. In the third quarter of 2007, we purchased 113.5 million gallons of ethanol at an average cost of $1.89 per gallon as compared to 142.7 million gallons of ethanol at an average cost of $2.21 in the third quarter of 2006.

Production costs include corn costs, conversion costs (defined as the cost of converting the corn into ethanol, and includes production salaries, wages and stock compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs) and depreciation and amortization. Corn costs in the third quarter of 2007 totaled $67.1 million or $3.81 per bushel, versus $29.1 million, or $2.31 per bushel in the third quarter of 2006. The increase in corn costs is due to a combination of the increased bushels of corn consumed by the new Pekin dry mill which came on-line in January 2007, along with increased demand in the marketplace as a result of expected new ethanol production facilities being built and increased demand for grains on a global basis.

Conversion costs for the third quarter of 2007 increased to $29.4 million from $21.5 million for the third quarter of 2006. The total dollars spent on conversion costs increased year over year as a result of the new Pekin dry mill production, and higher denaturant costs. However, the conversion cost per gallon declined year over year to $0.63 per gallon in the third quarter of 2007 versus $0.67 per gallon in the third quarter of 2006. Conversion costs per gallon in the third quarter of 2007 were negatively affected by lower production caused by a planned maintenance outage at our Pekin wet mill facility. Other than the planned outage at our Pekin wet mill, our facilities ran at approximately 94% of their theoretical capacity, assuming maximum denaturant blending, during the third quarter of 2007. Conversion costs per gallon in the third quarter of 2006 were negatively affected by lower production caused maintenance outages at both production facilities.

Depreciation in the third quarter of 2007 totaled $3.3 million, versus $0.6 million in the third quarter of 2006. The increase in depreciation expense is the result of the new Pekin dry mill beginning production. Motor fuel taxes were $2.3 million in the third quarter of 2007 versus $4.8 million in the third quarter of 2006. The cost of motor fuel taxes are recovered through billings to customers.

Freight/logistics costs in the third quarter of 2007 increased to $31.0 million, or approximately $0.19 per gallon, from $24.5 million, or $0.15 per gallon in the third quarter of 2006. Freight/logistics cost per gallon is calculated by taking total freight/logistics costs incurred and dividing by the total ethanol gallons sold. Total freight/logistics costs also include costs to ship co-products. The increase in freight costs was primarily due to higher general freight and barge expenses. Fuel surcharges continue to impact general freight rates.

The average inventory cost of $1.61 per gallon at the end of the third quarter of 2007 versus $1.98 at the end of the second quarter of 2007 reflects the sharp decline in ethanol prices during the quarter 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 the second quarter of 2007 during a period of declining prices was $9.0 million. Such decline in value was further affected by a $1.6 million non-cash lower of cost or market adjustment. In 2006, the average cost of inventory was $1.94 at the end of the third quarter as compared to $2.19 at the end of the second quarter of 2006. The economic impact of this same issue in the third quarter of 2006 was approximately $10.5 million.

Selling, general and administrative expenses (“SG&A”) expenses were $9.4 million in the third quarter of 2007, compared to $7.4 million in the third quarter of 2006. Year over year increases reflect increased expenditures for legal and other professional fees associated with being a public company, including the costs of complying with Section 404 of Sarbanes-Oxley Act of 2002 and increased IT costs. Increased legal fees related to our capacity expansion efforts also increased SG&A expenses.

Interest income in the third quarter of 2007 was $3.6 million, versus $1.4 million in the third quarter of 2006. The increase in interest income is due to a combination of a higher average level of funds available to invest as a result of our recent note offering and funds from last year’s initial public offering, combined with higher short-term investment rates due to increases in interest rates in general.

Interest expense in the third quarter of 2007 was $5.4 million, as compared to $0.7 million in the third quarter of 2006. Interest expense in the third quarter of 2007 increased due to the issuance in March 2007 of $300 million aggregate principal amount of 10.0% senior unsecured notes, offset by capitalized interest. In the third quarter of 2006, we had $5 million remaining outstanding from a previous issue of $160 million aggregate principal amount of floating rate senior secured notes.

The minority interest for the quarter ended September 30, 2007 was a $0.1 million charge to income compared to $0.9 million charge to income for the quarter ended September 30, 2006. This decrease 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 per gallon in the third quarter of 2007 from the sale of ethanol.

Other non-operating loss for the third quarter of 2007 includes $1.0 million of realized and unrealized gains on corn derivative contracts and realized and unrealized losses on the sale of forward gasoline contracts. These include the effect of marking to market these contracts at quarter end. For the third quarter of 2007, net realized and unrealized losses of $0.2 million were recorded on corn derivative contracts, and net realized and unrealized losses of $0.8 million were recorded on the sale of forward gasoline contracts. Other non-operating income is impacted by the CBOT prices for derivative contracts.

Our federal income tax returns covering fiscal years 2004 and 2005 had been under audit by the Internal Revenue Service (“IRS”). The audit was completed in September 2007. As a result, the Company was able to finalize positions relating to certain tax matters which required liability recognition under FIN 48. The Company recognized in the third quarter of 2007 a previously unrecorded favorable tax benefit of $9.6 million, which includes its previously recorded liability for uncertain tax benefits, the related interest and the release of code section 382 valuation allowances.

The Company's estimated annual tax rate for the third quarter of 2007, exclusive of the FIN 48 adjustment discussed above which resulted from concluding the recent IRS examination, is 23.4%. The difference between the Company's estimated annual tax rate and the statutory rate is primarily the result of significant amounts of tax-exempt interest income.

For the Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006

Total gallons sold in the first nine months of 2007 were 513.9 million gallons, versus 504.5 million gallons sold in the first nine months of 2006, an increase of 9.4 million gallons or 1.9%. Ethanol gallons sourced were as follows:

	For the Nine Months Ended September 30,
(In thousands, except for percentages)	2007	2006		Increase/ (Decrease)		% Increase/ (Decrease)
Equity production	146,410	97,677		48,733		49.9	%
Marketing alliance purchases	294,452	365,150		(70,698	)	(19.4	%)
Purchase/resale	72,434	49,439		22,995		46.5	%
Decrease/(increase) in inventory	652	(7,805	)	8,457		N.M.	*
Total	513,948	504,461		9,487		1.9	%

* Not meaningful

Net sales in the first nine months of 2007 were flat as compared to first nine months of 2006, at $1.2 billion for each nine month period. Overall, an increase in gallons sold was offset by a decline in the average sales price of ethanol. Gallons sold in the first nine months of 2007 increased as a result of a higher equity production from our new Pekin dry mill and a higher number of gallons purchased from other producers, offset by the lower number of gallons that were purchased from marketing alliance partners. The average gross selling price of ethanol in the nine months of 2007 decreased to $2.13 per gallon, from the $2.20 received in the first nine months of 2006.

Co-product revenue for the first nine months of 2007 totaled $70.3 million, an increase of $30.1 million or 74.9%, from the first nine month 2006 total of $40.2 million. Co-product revenue increased during the first nine months of 2007 versus 2006 principally from an increase in co-product tonnage sold as a result of the DDGS produced from the new dry mill production, along with higher average selling prices. In the first nine months of 2007, we sold 848.9 thousand tons, versus 681.9 thousand tons in the first nine months of 2006. Co-product revenues, as a percentage of corn costs, were 34.0% during the first nine months of 2007, versus 48.1% in the first nine months of 2006. Co-product returns, as a percentage of corn costs, decreased in the first nine months of 2007 as compared to 2006 as the result of increases in the price of corn continuing to outpace the increase in co-product pricing, and from the mix of co-products produced. Due to the addition of the new dry mill in Pekin, the increase in DDGS production increased the percentage of the lower value DDGS to the overall mix of available co-products.

Cost of goods sold for the first nine months of 2007 versus the first nine months of 2006 was flat at $1.1 billion. Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from our marketing alliance partners, the cost of purchasing ethanol and biodiesel from other producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers.

Purchased ethanol in the first nine months of 2007 totaled $722.3 million, versus $851.5 million in the first nine months of 2006. The decrease in purchased ethanol results from a decrease in the number of gallons of ethanol purchased, along with a decrease in the cost per gallon of ethanol purchased. In the first nine months of 2007, we purchased 366.9 million gallons of ethanol at an average cost of $1.97 per gallon as compared to 414.6 million gallons of ethanol at an average cost of $2.05 in the first nine months of 2006.

Production costs include corn costs, conversion costs (defined as the cost of converting the corn into ethanol, and includes production salaries, wages and stock compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs) and depreciation and amortization. Corn costs in the first nine months of 2007 totaled $206.5 million or $3.79 per bushel, versus $83.6 million, or $2.23 per bushel in the first nine months of 2006. The increase in corn costs is due to a combination increased bushels of corn consumed by the new Pekin dry mill which came on-line in January 2007, along with increased

demand in the marketplace as a result of expected new ethanol production facilities being built and increased demand for grains on a global basis.

Conversion costs for the first nine months of 2007 increased to $87.4 million from $65.0 million for the first nine months of 2006. The total dollars spent on conversion costs increased year over year principally as a result of the new Pekin dry mill production. However, the conversion cost per gallon declined year over year to $0.60 per gallon in the first nine months of 2007 versus $0.67 per gallon in the first nine months of 2006. Other than the planned outage at our Pekin wet mill taken during the third quarter of 2007, our facilities for the first nine months of 2007 ran at approximately 95% of their theoretical capacity, assuming maximum denaturant blending. Conversion costs per gallon in the first nine months of 2006 were negatively affected by lower production caused by maintenance outages at both production facilities.

Depreciation in the first nine months of 2007 totaled $9.3 million, versus $2.7 million in the first nine months of 2006. The increase in depreciation expense is the result of the new Pekin dry mill beginning production. Motor fuel taxes were $12.8 million in the first nine months of 2007 versus $10.4 million in the first nine months of 2006. The cost of motor fuel taxes are recovered through billings to customers.

Freight/logistics costs in the first nine months of 2007 increased to $89.2 million, or approximately $0.17 per gallon, from $76.5 million, or $0.14 per gallon in the first nine months of 2006. Freight/logistics cost per gallon is calculated by taking total freight/logistics costs incurred and dividing by the total ethanol gallons sold. Total freight/logistics costs also include costs to ship co-products. The increase in freight/logistics cost is principally from the expansion of our distribution system footprint, along with higher general freight and barge expenses. Fuel surcharges continue to impact general freight rates.

The average cost of inventory was $1.61 at the end of the third quarter of 2007 as compared to $1.91 at the end of the 2006 reflects the decline in ethanol prices using our weighted average FIFO approach to calculating inventory. The economic impact of selling gallons that were previously held in inventory in at the end of 2006 during a period of declining prices, was $7.0 million. Such decline in value was further affected by a $1.6 million lower of cost or market adjustment. The average cost of inventory was $1.94 at the end of the third quarter of 2006 as compared to $1.50 at the end of 2005. The economic impact of the same issue the first nine months of 2006 was $18.5 million.

SG&A expenses were $27.8 million in the first nine months of 2007, compared to $21.0 million in the first nine months of 2006. SG&A expenses increased as a result of increased costs related to being a public company, and from costs associated with the expansion and growth of our business. Year over year increases reflect increased expenditures for legal and other professional fees associated with our being a public company including the costs of complying with Section 404 of Sarbanes-Oxley Act of 2002 and increased IT costs. Increased legal fees related to our capacity expansion efforts also increased SG&A expenses.

Interest income in the first nine months of 2007 was $9.1 million, versus $3.3 million in the first nine months of 2006. The increase in interest income is due to a combination of a higher average level of funds available to invest as a result of our March 2007 note offering and funds from last year’s initial public offering, combined with higher short-term investment rates due to increases in interest rates in general.

Interest expense in the first nine months of 2007 was $12.7 million, as compared to $9.3 million in the first nine months of 2006. Interest expense in the first nine months of 2007 reflects interest incurred from March 2007 through September 2007 on our $300 million aggregate principal amount of

10.0% senior unsecured notes. In the first nine of 2006, we had outstanding a previous issue of $160 million aggregate principal amount of floating rate senior secured notes through July 2006, the majority of which was repurchased in July 2006.

The minority interest for the first nine months of 2007 was a $1.3 million charge to income compared to $3.8 million charge to income for the first nine months of 2006. This decrease reflects the reduced operating performance of our Nebraska subsidiary caused primarily by the year over year significant increase in corn costs along with a lower average price received per gallon in the first nine months of 2007 as compared to 2006 from the sale of ethanol.

Other non-operating income for the first nine months of 2007, we recorded $5.1 million of realized and unrealized gains on corn derivative contracts and realized and unrealized losses on the sale of forward gasoline contracts. These include the effect of marking to market these contracts at September 30, 2007. Net gains on corn derivatives totaling $5.9 million were offset by net losses on short gasoline forward contracts totaling $0.8 million. For the first nine months of 2006, we recognized $4.8 million of net realized and unrealized gains on corn derivative contracts. Other non-operating income is impacted by the CBOT prices for derivative contracts.

Our federal income tax returns covering fiscal years 2004 and 2005 had been under audit by the Internal Revenue Service (“IRS”). The audit was completed in September 2007. As a result, the Company was able to finalize positions relating to certain tax matters which required liability recognition under FIN 48. The Company recognized in the third quarter of 2007 a previously unrecorded favorable tax benefit of $9.6 million, which includes its previously recorded liability for uncertain tax benefits, the related interest and the release of Section 382 valuation allowances.

The Company's estimated annual tax rate for the first nine months of 2007, exclusive of the FIN 48 adjustment discussed above which resulted from concluding the recent IRS examination, is 23.4%. The difference between the Company's estimated annual tax rate and the statutory rate is primarily the result of significant amounts of tax exempt interest income.

Trends and Factors that May Affect Future Operating Results

Ethanol Pricing

Ethanol prices fell significantly during the third quarter of 2007. For example, the average price we received for ethanol sold in the second quarter was $2.29 per gallon as compared to $2.01 in the third quarter of 2007. The negative effect of lower ethanol prices significantly affected our gross profit during the third quarter of 2007. The decline in ethanol prices is the result of a supply/demand imbalance of ethanol relative to mandated ethanol usage. Ethanol was being sold at the end of the third quarter of 2007 at a significant discount to wholesale gasoline. This, combined with the $0.51 per gallon tax credit available to blenders, provides significant arbitrage opportunities to blenders to increase the amount of ethanol they are blending. However, we are unable to predict how long this supply/demand imbalance may last or how far ethanol prices may fall until the supply/demand equation becomes re-balanced.

As of September 30, 2007, we had contracts for delivery of ethanol totaling 191.6 million gallons for delivery through September 2008. These commitments were for 29.4 million gallons at an average fixed price of $1.80, 32.2 million gallons at an average spread to wholesale gasoline of negative $0.06 (based upon the NYMEX, Chicago and NY harbor indices), and 130.0 million gallons at spot prices (using various Platt, OPIS and AXXIS indices). For the fourth quarter of 2007, we have contracts for delivery of ethanol totaling 100.7 million gallons for delivery through December 2007. These commitments were for 8.4 million gallons at an average fixed price of $2.07, 25.7 million gallons at an

average positive spread to wholesale gasoline of $0.03 (based upon the NYMEX, Chicago and NY harbor indices), and 66.6 million gallons at spot prices (using various Platt, OPIS and AXXIS indices). At the end of the third quarter of 2007, we also had short gasoline positions outstanding using swap agreements where we sold 16.0 million gallons of gasoline at an average fixed price of $2.01 per gallon for delivery from October 2007 through December 2008. We did this to hedge some of our gas plus contracts from potentially falling gasoline prices. The mark to market value of these positions at September 30, 2007 was a loss of approximately $1.0 million.

Corn

Corn prices have risen significantly since the second quarter of 2006. While corn prices have subsided from the highs seen in early 2007, they remain high compared to historical averages. 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 also typically short a like amount of CBOT corn futures with similar dates to lock in the basis differential. At the end of the third quarter of 2007, we had forward physical delivery purchase contracts covering 8.2 million bushels through December 2009 at an average price of $3.72 per bushel. Approximately 4.8 million bushels of these positions are for the fourth quarter of 2007. Our forward physical delivery contracts are not marked to market and have been offset by the sale of CBOT futures positions covering 7.5 million bushels of corn with an average price of $3.82 per bushel. These short positions are marked to market each period, with corresponding gains and losses recorded in other non-operating income at the end of each period.

Our corn purchases typically range from 18.0 to 19.0 million bushels per quarter. Given our relatively small percentage of forward purchases, we are, for all intents and purposes, in the local spot market for corn.

Marketing Alliance

Our marketing alliance annualized volume at the end of the third quarter of 2007 remained at 361 million gallons. We expect to increase our marketing alliance volumes during the fourth quarter of 2007 by 100 million gallons on an annualized basis. Our expectation is based on the start-up of, an expansion by Glacial Lakes Ethanol, of Watertown, SD and a new plant called E Energy Adams, LLC, in Adams, NE, both with an annual nameplate capacity of 50 million gallons. When these new plant/expansions becomes operational, and including our own recent Pekin dry mill, we will be marketing 668 million gallons of ethanol in the U.S. annually, nearly matching the total at the end of 2006. In addition, we have signed marketing agreements with another 17 plants with nameplate production capacity of 1.5 billion gallons, with 301 million gallons currently under construction and 1.2 billion gallons for projects that have been announced. Construction of these proposed projects has not commenced, and there can be no assurances that these projects will be commenced or completed on a timely basis, or at all.

Supply and Demand

It is expected that annual ethanol production capacity in the U.S. will total in excess of 7.5 billion gallons annually by the end of 2007, which is the amount required by the existing renewable fuel standard for 2012. Ethanol produced in the United States competes with sugar-based ethanol produced in Brazil. This additional 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 governmental mandates at either the federal

or state level, the excess supply may cause ethanol prices to remain depressed or decrease further, perhaps substantially.

Expansion

We have identified opportunities to increase our equity production capacity through the development of new production facilities and are continually exploring acquisition opportunities. In addition to the 57 million gallon dry mill expansion of our Pekin, Illinois facility which was completed in early 2007, we have begun building 113 million gallon annualized capacity ethanol production facilities at both Mt. Vernon, Indiana and Aurora, Nebraska which we intend to substantially complete by the end of 2008.

We also intend to add an additional 113 million gallons of capacity through phase II expansions at both Mt. Vernon, Indiana and Aurora, Nebraska, along with potentially expanding our existing Pekin, Illinois campus. The timing of the remaining expansions will be based upon, among other factors, market conditions and the availability of financing on attractive terms.

On September 20, 2007, we received an air quality construction permit from the Indiana Department of Environmental Management. On September 27, 2007, we received an air quality construction permit from the Nebraska Department of Environmental Quality. Each permit allows us to build ethanol production facilities that are capable of producing up to 226 million gallons of fuel-grade denatured ethanol. Kiewit Energy Company is the contractor for these projects, and Delta-T Corporation is the technology provider and a sub-contractor. We are still awaiting other permits, such as waste water discharge permits, that will be necessary in order to operate the plants (although other permit applications have been filed). Accordingly, we cannot give assurance that these expansion projects will be completed on a timely basis or at all or that we will realize the benefits we anticipate. In addition, while we expect to raise additional funds for the phase II facility additions, we cannot be sure that we will be able to obtain such additional funding for these phase II transactions on attractive terms or at all. In addition, we may have to pay penalties or damages under certain contracts related to such capacity expansions.

Bio-Diesel

During the third quarter of 2007, we sold 3.1 million gallons of biodiesel. Although this program is still in its early stages, we are adding additional resources toward its growth.

Liquidity and Capital Resources

Overview and Outlook

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

(In thousands)	September 30, 2007		December 31, 2006
	(Unaudited)

Cash and cash equivalents	$	39,424	$	29,791
Short-term investments	282,868		98,925
Working capital	381,597		203,247
Total debt	300,000		—
Current ratio	6.50		3.44

On May 31, 2007, we entered engineering, construction and procurement contracts (“EPC”) contracts to build two initial 113 million gallon ethanol production facilities in Mount Vernon, Indiana and Aurora, Nebraska. These EPC contracts call for payments to Kiewit in the amount of $462.5

million. Certain owner project costs are excluded from the EPC contracts. These include, but are not limited to, the cost of land, as well as the cost of bringing power, water sewer and natural gas service to the sites. Each of the EPC contracts also allows for credits against the contract total for amounts paid for materials and services under each of an advance work agreement entered into with Delta-T Corporation in March 2007 and a pre-EPC agreement entered into with Kiewit in March 2007. The EPC contracts also call for Kiewit to provide certain additional materials and services to prepare each site for a phase II expansion. A phase II expansion would double the capacity of each of the above plants. The Company has received the necessary air quality construction permits for the full 226 million gallons of annual production capacity at each site. While we expect to raise additional funds for the Aurora West and Mt. Vernon phase II facility additions as well as the Pekin III facility, we cannot be sure that we will be able to obtain such additional funding for these transactions on attractive terms or at all.

We are contractually obligated, subject to certain conditions, including obtaining necessary permits, to develop both a 113 million gallon plant adjacent to our Nebraska facility and a 226 million gallon plant in Mount Vernon, Indiana. If we do not meet certain specified milestones, we will be subject to penalties. The contract to complete the expansion adjacent to our Nebraska facility provides for liquidated damages not exceeding $5 million if specified milestones are not met or we do not construct a facility with a capacity of at least 110 million gallons. If such penalties are not paid, the counterparty to the contract has the right to repurchase the property at cost (subject to adjustment for any expenses, which we have paid with respect to infrastructure construction). In certain cases, the counterparty can agree to an extension and limited cure rights for payments. The contract for completion of the 226 million gallon plant in Mount Vernon, Indiana provides that, if we do not meet certain milestones, subject to specified extension rights and cure periods, we will be in default under our lease with the Indiana Port Commission. The State of Indiana may complete construction of the plant at our expense if we fail to do so. The contract does not provide for liquidated damages as an alternative. In addition, we would also be subject to certain other penalties provided for in the lease.

With our current cash balances, amounts available under our secured revolving credit facility and anticipated cash flow from operations, we believe that we will be able to satisfy existing anticipated working capital needs, debt service obligations, capital expenditure and other anticipated cash requirements for the remainder of the year. If the commodity spread which existed at the end of the third quarter of 2007 continues or worsens, we may need to either delay our expansion plans or raise additional capital.

Sources of Liquidity

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

Cash and short-term investments. For the first nine months of 2007, cash and short-term investments increased by $193.6 million. Cash and short-term investments as of September 30, 2007 and December 31, 2006 were $322.3 million and $128.7 million, respectively. The increase in cash and short-term investments is principally the result of cash received from the private placement of $300 million aggregate principal amount of senior unsecured 10% fixed rate notes, net of fees, along with cash provided by operations, offset by expenditures related to our plant expansions.

Cash provided by operations. Net cash provided by operating activities in the first nine months of 2007 was $53.8 million, as compared to cash provided by operating activities of $21.7 million for the first nine months of 2006. The increase in cash provided by operations in 2007 versus 2006 is primarily the result of decreased working capital requirements caused by lower ethanol prices. Cash on our

balance sheet, the cash received from the issuance of the $300 million of 10% senior unsecured notes and these reductions in working capital requirements has significantly helped our working capital position.

Cash available under our liquidity facility. Our liquidity facility consists of a five-year $200 million senior secured revolving credit facility that may, under certain circumstances, increase in amount up to $300 million. Collateral availability is determined via a borrowing base which, includes a portion of receivables and inventory, and $50 million of property, plant and equipment. We had no borrowings outstanding under our secured revolving credit facility at September 30, 2007 and $1.5 million of standby letters of credit outstanding, leaving approximately $116.2 million in additional borrowing availability thereunder as of that date. In October 2007, we issued additional letters of credit totaling $15.3 million in conjunction with our current plant expansions. These letters of credit further reduced the availability under our liquidity facility by $15.3 million. In the third quarter of 2007, we added $50 million in additional availability to our liquidity facility. Such additional availability was secured by $50 million of property, plant and equipment. As of December 31, 2006, we had no borrowings outstanding under our previous secured revolving credit facility and $4.0 million of standby letters of credit outstanding, leaving approximately $26.0 million in additional borrowing availability under the previous secured revolving credit facility as of that date.

Uses of Liquidity

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

Capital expenditures. In the first nine months of 2007, capital expenditures (excluding expansion related expenditures) totaled $11.6 million versus $5.1 million in the first nine months of 2006. Capital expenditures include asset replacement, environmental and safety compliance and cost reduction and productivity improvement items. Our capital spending plan for all of 2007, excluding our expansion projects, is forecasted to be approximately $14 million.

Capital expenditures related to our announced expansion projects totaled $138.3 million in the first nine months of 2007. Expenditures for capital expansion projects in 2007 include $64.5 million on Mt. Vernon, $69.1 million on Aurora West, and $4.7 million on our new Pekin dry mill facility. Our total capital expenditures on capacity expansion projects is now expected to total approximately $250 million for 2007.

Payments related to our outstanding debt and liquidity facility. In the first nine months of 2007, we did not make any interest payments on our debt or our liquidity facility. In the first nine months of 2006, we paid $10.2 million in interest payments on our debt and liquidity facility.

Repurchase of shares of common stock. In the third quarter and for the nine months ended September 30, 2007, we repurchased 71,300 shares of our common stock on the open market at a total cost of $1.0 million. The share repurchase program allows the repurchase of up to $50 million of our outstanding common stock, although there are no minimum share purchase requirements. There is approximately $47.8 million available to be repurchased under this program.

Environmental Matters

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

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

We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged for the disposal of hazardous wastes. From time to time, hazardous material spills have occurred at our facilities or properties, which we investigate and remediate as necessary. Also, soil and groundwater contamination has been identified in the past at our Pekin, Illinois campus. If significant contamination is identified at our properties in the future, costs to investigate and remediate this contamination as well as any costs to investigate or remediate associated natural resource damages could be significant. If any of these sites are subject to investigation and/or remediation requirements, we may be responsible under CERCLA or other environmental laws for all or part of the costs of such investigation and/or remediation, and for damages to natural resources. We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties. We have not accrued any amounts for environmental matters as of September 30, 2007. The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

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

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

Federal and state environmental authorities have been investigating alleged excess VOC emissions and other air emissions from many U.S. ethanol plants, including our Illinois and Nebraska

facilities. The matter relating to our Illinois wet mill facility is still pending, and we could be required to install costly additional air pollution control equipment or take other measures to control air pollutant emissions at that facility. In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.

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. So far in 2007, we have spent approximately $2.6 million on these matters. We expect to have to eventually make significant capital expenditures to comply with the EPA’s final National Emissions Standard for Hazardous Air Pollutants, or NESHAP, under the federal Clean Air Act for industrial, commercial and institutional boilers and process heaters. This NESHAP requires us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from certain of our boilers and process heaters. We have been granted an extension until September 12, 2008 to complete work under this NESHAP. Based on engineering conducted to date and currently available information, we expect to eventually spend a total of $7.4 million to comply with this NESHAP. If we do not meet this September 2008 deadline, fines and penalties could be imposed on us, which could be substantial.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including changes in commodity prices and interest rates. Market risk is the potential loss arising from adverse changes in market rates and prices. In the ordinary course of business, we enter into various types of transactions involving financial instruments to manage and reduce the impact of changes in commodity prices and interest rates. 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 global demand and supply. Our weighted average gross corn costs for the three months ended September 30, 2007 and 2006 was $3.81 and $2.31 per bushel, respectively. For the nine month periods ended September 30, 2007 and 2006, our weighted average corn costs were $3.79 and $2.23 per bushel, respectively.

We have firm-price purchase commitments with some of our corn suppliers under which we agree to buy corn at a price set in advance of the actual delivery of that corn to us. At September 30, 2007, we had commitments to purchase approximately 8.1 million bushels of corn through December 2009 at an average price of $3.72 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 like amount of corn at the then-current price for delivery to the counterparty at a later date. We account for these 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, 2007

Realized and unrealized gains included in earnings in 2007	$	4.8

(In millions)	September 30, 2007

Net bushels sold	6.8
Aggregate notional value of derivatives outstanding	$	28.6
Period through which derivative positions currently exist	December 2009
Unrealized gain on the fair value of outstanding derivative positions	$	(0.3	)
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$	(2.9	)

We are also subject to market risk with respect to ethanol pricing. Our ethanol sales are priced using contracts that can either be fixed; based upon the price of wholesale gasoline plus or minus a fixed amount; or based upon a market price at the time of shipment. We sometimes fix the price at which we sell ethanol using fixed price physical delivery contracts. At September 30, 2007, we had fixed contracts to sell approximately 29.4 million gallons of ethanol at an average fixed price of $1.80 per gallon through September 2008. These normal purchase/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, 2007, we had sold forward approximately 32.2 million gallons of ethanol using wholesale gasoline as an index plus a fixed spread that averaged a negative $0.06 per gallon. Under these arrangements, we assume the risk of a price decrease in the market price of gasoline. In order to reduce our market exposure to price decreases, at the time we enter into a firm sales commitment, we may also enter into commodity forward contracts to sell a like amount of gasoline at the then-current price for delivery to the counterparty at a later date. We account for these transactions under SFAS 133. These forward contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income. The fair value of these derivative liabilities is recognized in other current liabilities in the Condensed Consolidated Balance Sheet, net of any cash paid to brokers. Information on this type of derivative transaction is as follows:

(In millions)	September 30, 2007

Realized and unrealized loss included in earnings	$	(0.8	)

(In millions)	September 30, 2007

Gallons sold	16.0
Aggregate notional value of derivatives outstanding	$	32.2
Period through which derivative positions currently exist	December 2008
Unrealized loss on the fair value of outstanding derivative positions	$	(1.0	)
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$	(3.3	)

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.

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.

Item 4 and Item 4T. Internal Control Over Financial Reporting

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.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

The Company has included in its Annual Report on Form 10-K as of December 31, 2006 a description of certain risks and uncertainties that could affect the Company’s business, future performance or financial condition (“Risk Factors”). Those Risk Factors are hereby incorporated in Part II, Item 1A of this Form 10-Q.

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

The following table presents information with respect to repurchases of Common Stock made by the Company during the quarter ended September 30, 2007. All of the repurchased shares were purchased on the open market under a share repurchase plan approved by the Board of Directors.

Period	Total Number of Shares Purchased	Average Price Paid Per Share (1)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value that May Yet Be Purchased Under the Plans or Programs
7/01/07 — 7/31/07	—	$	—	—	$	—
8/01/07 — 8/31/07	71,300	13.93		121,300	47,855,000
9/01/07 — 9/30/07	—	—		—	—
Total	71,300	$	13.93	121,300	$	47,855,000

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

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

	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.

	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, 2007	By:	/s/ William J. Brennan
	Name:	William J. Brennan
	Title:	Principal Accounting Officer