FORM 10-Q

FORM 10-Q

SIGNATURE

Qualified Retirement Plan

Postretirement Benefit Obligation

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

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 August 3, 2007
Common Stock, $0.001 Par Value		41,931,370 Shares

QUARTERLY REPORT

TABLE OF CONTENTS

		Page No.
	PART I

Item 1.	Financial Statements
	Condensed Consolidated Statements of Operations (Unaudited) — Three and six month periods ended June 30, 2007 and 2006	1
	Condensed Consolidated Balance Sheets — June 30, 2007 (Unaudited) and December 31, 2006	2
	Condensed Consolidated Statements of Cash Flows (Unaudited) — Six months ended June 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.	Controls and Procedures	32

	PART II

Item 1.	Legal Proceedings	32

Item 1A.	Risk Factors	32

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 June 30,						Six months ended June 30,
*(In thousands except per share amounts)*	2007			2006			2007			2006

Net sales	$	394,914		$	442,905		$	831,576		$	756,425
Cost of goods sold	367,485			392,697			775,732			675,622
Gross profit	27,429			50,208			55,844			80,803
Selling, general and administrative expenses	8,779			7,371			18,377			13,637
Other (income)	(514		)	(342		)	(678		)	(607		)
Operating income	19,164			43,179			38,145			67,773
Other income (expense):
Interest income	4,167			1,228			5,535			1,883
Interest expense	(7,021		)	(4,236		)	(7,357		)	(8,601		)
Other non-operating income	2,139			1,899			6,008			2,454
Minority interest	(725		)	(1,651		)	(1,243		)	(2,917		)
Income before income taxes	17,724			40,419			41,088			60,592
Income tax expense	5,117			15,765			13,541			23,751
Net income	$	12,607		$	24,654		27,547			$	36,841

Per share data:
Income per common share — basic:	$	0.30		$	0.70		$	0.66		$	1.05
Basic weighted average number of common shares	41,912			35,152			41,861			35,149

Income per common share — diluted:	$	0.30		$	0.67		$	0.65		$	1.01
Diluted weighted average number of common and common equivalent shares	42,649			36,572			42,554			36,527

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)*	June 30, 2007 (Unaudited)			December 31, 2006

Assets
Current assets
Cash and cash equivalents	$	44,059		$	29,791
Short-term investments	341,773			98,925
Accounts receivable	48,897			79,729
Inventories	74,923			67,051
Income tax receivable	5,220			6,446
Prepaid expenses and other	5,821			4,549
Total current assets	520,693			286,491

Property, plant and equipment, net	188,023			115,645
Net deferred tax assets	2,345			—
Other assets	13,991			6,000
Total assets	$	725,052		$	408,136

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	50,655		$	77,442
Accrued liabilities	4,156			3,679
Accrued interest payable	7,833			—
Other current liabilities	3,281			2,123
Total current liabilities	65,925			83,244

Senior unsecured 10% notes due April 2017	300,000			—
Minority interest	9,953			10,221
Net deferred taxes liabilities	—			6,104
Other long-term liabilities	13,639			4,404
Total liabilities	389,517			103,973

Stockholders’ equity
Common stock, par value $0.001 per share; 185,000,000 shares authorized; 41,921,370 and 41,782,276 shares issued and outstanding as of June 30, 2007 and December 31, 2006, respectively, net of 21,229,025 shares held in treasury as of June 30, 2007 and December 31, 2006	42			42
Preferred stock, 50,000,000 shares authorized, no shares issued or outstanding	—			—
Additional paid-in capital	277,869			274,307
Retained earnings	58,683			30,888
Accumulated other comprehensive loss	(1,059		)	(1,074		)
Total stockholders’ equity	335,535			304,163
Total liabilities and stockholders’ equity	$	725,052		$	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)

	Six months ended June 30,
*(In thousands)*	2007			2006

Operating Activities
Net income	$	27,547		$	36,841
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	6,205			2,765
Minority interest	1,243			2,917
Stock-based compensation expense	3,345			3,053
Deferred income tax	1,373			(620		)
Other	248			(36		)
Changes in operating assets and liabilities:
Accounts receivable, net	30,832			(10,516		)
Inventories	(7,872		)	(19,043		)
Accounts payable	(26,787		)	25,914
Other changes in operating assets and liabilities	8,851			2,260
Net cash provided by operating activities	44,985			43,535

Investing Activities
Additions to property, plant and equipment, net	(78,354		)	(31,610		)
Investment in short-term securities	(242,848		)	—
Increase in restricted cash for investing activities	—			(1,110		)
Use of restricted cash for plant expansion	—			27,658
Net cash used for investing activities	(321,202		)	(5,062		)

Financing Activities
Proceeds from issuance of senior unsecured notes	300,000			—
Payment of debt issuance costs	(8,221		)	—
Proceeds from stock option exercises	200			—
Tax benefit of stock option exercises	17			—
Net repayments on revolving credit facilities	—			(1,514		)
Distributions to minority shareholders	(1,511		)	(1,727		)
Net cash provided by (used for) financing activities	290,485			(3,241		)
Net increase in cash and cash equivalents	14,268			35,232
Cash and cash equivalents at beginning of period	29,791			3,750
Cash and cash equivalents at end of period	$	44,059		$	38,982

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 six month periods ended June 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 June 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.

(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)	June 30, 2007		December 31, 2006

Finished products	$	67,228	$	61,775
Work-in-process	2,408		1,106
Raw materials	3,093		2,070
Supplies	2,194		2,100
Totals	$	74,923	$	67,051

(5) Prepaid Expenses and Other

Prepaid expenses and other are as follows:

(In thousands)	June 30, 2007		December 31, 2006

Fair value of derivative instruments	$	2,521	$	1,503
Prepaid insurance	1,537		1,280
Deferred income taxes current	981		1,064
Other prepaid expenses	782		702
Totals	$	5,821	$	4,549

(6) Other Assets

Other assets are as follows:

(In thousands)	June 30, 2007		December 31, 2006

Deferred debt issuance costs	$	7,991	$	—
Investment in marketing alliances	6,000		6,000
Totals	$	13,991	$	6,000

Deferred debt issuance costs are subject to amortization. Remaining deferred debt issuance costs of $7.1 million related to our 10% senior unsecured notes will be amortized utilizing a method which approximates the effective interest method over the remaining life of 10 years, resulting in amortization expense of $0.4 million over the remaining six months of 2007, and $0.7 million yearly thereafter. Remaining deferred debt issuance costs of $0.9 million related to our secured revolving credit facility will be amortized utilizing a method which approximates the effective interest method over the five year remaining life, resulting in amortization expense of $0.1 million over the remaining six months of 2007, and $0.2 million in each of the next four succeeding years beginning in 2008.

(7) Debt

The following table summarizes long-term debt:

(In thousands)	June 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. We had no borrowings outstanding under our secured revolving credit facility at June 30, 2007, and $1.2 million of standby letters of credit outstanding, leaving approximately $70.8 million in additional borrowing availability under our secured revolving credit facility as of that date. 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.

A fixed asset component in an amount of $50 million may be added to the borrowing base on or prior to December 31, 2007 upon the satisfaction of certain requirements. We are in the process of satisfying the requirements necessary in order to take advantage of this fixed asset component.

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.

Our 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.

We have registered the Notes through a shelf registration statement in accordance with a registration rights agreement. The shelf registration statement was declared effective on July 12, 2007. We are currently conducting an exchange offer to exchange the Notes for an issue of registered unsecured senior notes, with terms identical to the Notes. If by October 23, 2007 we have not consummated a registered exchange offer for the Notes, the annual interest rate on the Notes will increase by 0.25% and by 0.25% for each subsequent 90 day period, up to a maximum 1.00% over the stated fixed rate of the Notes.

(8) Other Long-Term Liabilities

Other long-term liabilities are as follows:

(In thousands)	June 30, 2007		December 31, 2006

Reserve for uncertain tax positions (See Note 12)	$	8,991	$	—
Accrued interest on Uncertain tax positions (See Note 12)	701		—
Accrued pension and postretirement	2,181		2,427
Unearned commissions	1,766		1,977
Totals	$	13,639	$	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 SAB 107. Our options have characteristics significantly different from those of traded options, and changes in the assumptions can materially affect the fair value estimates.

Beginning in 2007, the Company commenced an ongoing long-term incentive program under the Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan, as amended (the “Plan”). It is anticipated that this program will provide regular annual grants of performance shares. Performance shares are stock units that will be converted to common shares, to the extent earned, at the end of a three-year performance cycle. 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 June 30, 2007 was $1.8 million, of which $0.1 million was charged to cost of goods sold and $1.7 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 June 30, 2007. For the three month period ended June 30, 2006, pre-tax stock-based compensation expense was $1.7 million, all of which was charged to selling, general and administrative expense. This expense reduced earnings per share by $0.05 per basic and diluted share for the quarter ended June 30, 2006. For the six month period ended June 30, 2007, pre-tax stock-based compensation expense was $3.4 million, of which $0.1 million was charged to cost of goods sold and $3.3 million was charged to selling, general and administrative expense. This expense reduced earnings per share for the six month period ended June 30, 2007 by $0.05 per basic and diluted share. For the six month period ended June 30, 2006, pre-tax stock-based compensation expense was $3.0 million, all of which was charged to selling, general and administrative expense. This expense reduced earnings per share for the six month period ended June 30, 2006 by $0.09 per basic share and $0.08 per diluted share. The Company recognized a tax benefit on its condensed consolidated statement of income from stock-based compensation expense in the amount of $0.5 million and $0.7 million for the three month periods ended June 30, 2007 and 2006, respectively, and in the amount of $1.0 million and $1.2 million for the six month periods ended June 30, 2007 and 2006, respectively. The Company recorded pre-tax stock-based compensation expense for the three and six month periods ended June 30, 2007 and 2006 as follows:

	Three months ended June 30,				Six months ended June 30,
*(in millions)*	2007		2006		2007		2006

Stock-based compensation expense:
Non-qualified stock options	$	1.5	$	1.7	$	3.0	$	3.0
Restricted stock	$	0.1	$	—	$	0.2	$	—
Restricted stock units	$	0.1	$	—	$	0.1	$	—
Long-term incentive stock plan	$	0.1	$	—	$	0.1	$	—

As of June 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	$	19.1	7.6	$	23.1	3.4
Restricted stock	1.2		4.4	0.2		2.8
Restricted stock units	0.1		1.4	—		—
Long-term incentive stock plan	1.6		2.5	—		—
Total	$	22.0	7.0	$	23.3	3.4

The Company granted stock options during the quarters ended June 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 June 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 June 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	4.9		%	4.9		%
Expected dividend yield	0.0		%	0.0		%
Weighted average fair value	$	10.57		$	13.77

The following table summarizes stock options outstanding and changes during the six month period ended June 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	265	15.76		9.9	—
Exercised	69	2.92		—	—
Cancelled or expired	28	4.35		—	—
Options outstanding — June 30, 2007	3,433	$	7.37	7.7	$	32,957
Options exercisable — June 30, 2007	1,174	$	3.52	6.8	$	15,790

The range of exercise prices of the exercisable options and outstanding options at June 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	750	1,070	6.0
$2.36 - $2.92	199	744	7.9
$4.35	99	684	8.3
$15.26 - $17.29	—	265	9.7
$22.15 - $22.50	118	630	8.8
$43.00	8	40	9.0
Totals	1,174	3,433	7.7

Restricted stock award activity for the six months ended June 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 — June 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 six months ended June 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	10.6	16.90
Vested	—	—
Cancelled or expired	—	—
Restricted stock unit awards — June 30, 2007	10.6	$	16.90

(10) Interest Expense

The following table summarizes interest expense:

	Three months ended June 30,						Six months ended June 30,
*(in thousands)*	2007			2006			2007			2006

Interest expense	$	7,500		$	4,450		$	7,836		$	8,695
Amortization of deferred debt issuance costs	229			333			229			667
Capitalized interest	(708		)	(547		)	(708		)	(761		)
Interest expense, net	$	7,021		$	4,236		$	7,357		$	8,601

(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 June 30, 2007 and 2006 of $0.3 million and $0.3 million, respectively, and expense of $0.7 million and $0.6 million for the six month periods ended June 30, 2007 and 2006, respectively. Contributions made under our defined contribution plans include a match, at the Company’s discretion, of employee contributions to the plans.

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 June 30,						Six months ended June 30,
*(In thousands)*	2007			2006			2007			2006

Service cost	$	88		$	71		$	176		$	142
Interest cost	124			107			248			215
Expected return on plan assets	(180		)	(128		)	(360		)	(256		)
Amortization of prior service costs	11			—			22			—
Amortization of net actuarial loss	6			12			12			24
Net periodic pension cost	$	49		$	62		$	98		$	125

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 June 30,				Six months ended June 30,
*(In thousands)*	2007		2006		2007		2006

Service cost	$	38	$	54	$	76	$	108
Interest cost	34		44		68		88
Amortization of prior service cost	—		15		—		30
Net periodic postretirement cost	$	72	$	113	$	144	$	226

(12) Income Taxes

The Company lowered its estimated annual tax rate for 2007 during the second quarter to adjust its income tax rate for the six month period ending June 30, 2007 to 32.5%, which is the rate we now estimate we will incur for 2007. This was done to reflect both a higher level of tax exempt interest

income from investments and from a lower level of pre-tax income as compared to our first quarter of 2007 estimate. This year to date true-up reduced the second quarter 2007 income tax expense by $0.6 million. This change in estimate increased second quarter 2007 basic and diluted earnings per share by $0.02 per share.

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. All of our unrecognized tax benefits, if recognized in future periods, would impact the Company’s effective tax rate. During the three and six month periods ended June 30, 2007, our liability for unrecognized tax benefits increased by $0.5 million and $0.9 million, respectively. At June 30, 2007, our liability for unrecognized tax benefits was $9.5 million, and is included in other long-term liabilities on the condensed consolidated balance sheet.

We include interest expense or income, as well as potential penalties on unrecognized tax benefits, as a component 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 is included in other long-term liabilities. We increased our accrual for interest related to uncertain tax positions by $0.1 million and $0.2 million, respectively, net of the deferred tax benefit, for the three and six month periods ended June 30, 2007. Our liability for accrued interest on unrecognized tax benefits at June 30, 2007 was $0.7 million, net of the deferred tax benefit, and is included in other long-term liabilities on the condensed consolidated balance sheet.

Our federal income tax returns for 2003 to 2006 are open tax years. We file in numerous state jurisdictions with varying statutes of limitation open from 2002 through 2006 depending on each jurisdiction’s statute of limitation. In 2006, the IRS commenced an examination of our U.S. income tax return. The Company expects this examination to be concluded and settled within the next 12 months. Based on the outcome of this examination, or as a result of the expiration of statute of limitations for specific jurisdictions, our unrecognized tax benefits for tax positions taken on previously filed tax returns possibly will materially change from the unrecognized tax benefits recorded as other long-term liabilities in our financial statements at January 1, 2007. In addition, the outcome of these examinations may impact the valuation of certain deferred tax assets in future periods. As a result, based on the status of these examinations, and the protocol of finalizing audits by the relevant tax authorities, which could include formal legal proceedings, it is not possible to estimate the impact of any amount of such changes, if any, to previously recorded uncertain tax positions.

(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 June 30,				Six months ended June 30,
*(In thousands, except per share data)*	2007		2006		2007		2006

Net income	$	12,607	$	24,654	$	27,547	$	36,841

Weighted average shares and share equivalents outstanding:
Basic shares	41,912		35,152		41,861		35,149
Dilutive non-qualified stock options and RSU’s	737		1,420		693		1,378
Diluted weighted average shares and share equivalents	42,649		36,572		42,554		36,527

Income per common share - basic:	$	0.30	$	0.70	$	0.66	$	1.05
Income per common share - diluted:	$	0.30	$	0.67	$	0.65	$	1.01

We had additional potential dilutive securities outstanding representing 530,000 common shares for the three month period ended June 30, 2007 that were not included in the computation of potentially dilutive securities because the options’ exercise prices were greater than the average market price of the common shares.

(14) Industry Segment

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

(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 June 30, 2007
(Unaudited)

*(In thousands)*	Parent			Subsidiary Guarantors			Non-Guarantor Subsidiary			Eliminations			Consolidated
Net sales	$	—		$	392,579		$	26,646		$	(24,311	)	$	394,914
Cost of goods sold	—			369,835			21,711			(24,061		)	367,485
Gross profit	—			22,744			4,935			(250		)	27,429
Selling, general and administrative expenses	73			8,248			708			(250		)	8,779
Other expense (income)	—			(510		)	(4		)	—			(514		)
Operating income (loss)	(73		)	15,006			4,231			—			19,164
Other income (expense):
Interest income	—			4,135			32			—			4,167
Interest expense	(6,972		)	(49		)	—			—			(7,021		)
Investment in subsidiaries	24,769			3,415			—			(28,184		)	—
Other non-operating income (expense)	—			2,478			(339		)	—			2,139
Minority interest	—			—			—			(725		)	(725		)
Income before income taxes	17,724			24,985			3,924			(28,909		)	17,724
Income tax expense	5,117			6,346			—			(6,346		)	5,117
Net income	$	12,607		$	18,639		$	3,924		$	(22,563	)	$	12,607

Aventine Renewable Energy Holdings, Inc. and Subsidiaries
Condensed Consolidating Statements of Operations
For the Six Months Ended June 30, 2007
(Unaudited)

*(In thousands)*	Parent			Subsidiary Guarantors			Non-Guarantor Subsidiary			Eliminations			Consolidated
Net sales	$	—		$	831,955		$	48,569		$	(48,948	)	$	831,576
Cost of goods sold	—			783,771			40,409			(48,448		)	775,732
Gross profit	—			48,184			8,160			(500		)	55,844
Selling, general and administrative expenses	236			17,167			1,474			(500		)	18,377
Other expense (income)	—			(674		)	(4		)	—			(678		)
Operating income (loss)	(236		)	31,691			6,690			—			38,145
Other income (expense):
Interest income	—			5,477			58			—			5,535
Interest expense	(7,308		)	(49		)	—			—			(7,357		)
Investment in subsidiaries	48,632			5,646			—			(54,278		)	—
Other non-operating income (expense)	—			5,867			141			—			6,008
Minority interest	—			—			—			(1,243		)	(1,243		)
Income before income taxes	41,088			48,632			6,889			(55,521		)	41,088
Income tax expense	13,541			15,805			—			(15,805		)	13,541
Net income	$	27,547		$	32,827		$	6,889		$	(39,716	)	$	27,547

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

(In thousands)	Parent		Subsidiary Guarantors		Non-Guarantor Subsidiary		Eliminations			Consolidated
Assets
Current assets
Cash and cash equivalents	$	—	$	39,699	$	4,360	$			$	44,059
Short-term investments	—		341,773		—					341,773
Accounts receivable, net	—		48,668		229					48,897
Inventories	—		73,175		1,748					74,923
Income tax receivable	—		5,220		—					5,220
Intercompany receivable	310,989		—		920		(311,909		)	—
Other assets	6		5,556		259					5,821
Total current assets	310,995		514,091		7,516		(311,909		)	520,693

Property, plant and equipment, net	—		169,058		18,965					188,023
Investment in subsidiaries	325,281		42,871		—		(368,152		)	—
Net deferred tax assets	—		2,345		—					2,345
Other assets	7,092		6,899		—					13,991
Total assets	$	643,368	$	735,264	$	26,481	$	(680,061	)	$	725,052

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	—	$	46,405	$	4,250	$	—		$	50,655
Accrued liabilities	—		3,883		273		—			4,156
Other current liabilities	7,833		3,144		137		—			11,114
Intercompany payable	—		311,909		—		(311,909		)	—
Total current liabilities	7,833		365,341		4,660		(311,909		)	65,925

Long-term debt	300,000		—		—					300,000
Minority interest	—		—		—		9,953			9,953
Other long-term liabilities	—		13,639		—					13,639
Total liabilities	307,833		378,980		4,660		(301,956		)	389,517
Stockholders’ equity	335,535		356,284		21,821		(378,105		)	335,535
Total liabilities and stockholders’ equity	$	643,368	$	735,264	$	26,481	$	(680,061	)	$	725,052

Aventine Renewable Energy Holdings, Inc. and Subsidiaries
Condensed Consolidating Statements of Cash Flows
For the Six Months Ended June 30, 2007
(Unaudited)

*(In thousands)*	Parent			Subsidiary Guarantors			Non-Guarantor Subsidiary			Eliminations		Consolidated
Operating Activities
Net cash provided by (used for) operating activities	$	(291,996	)	$	328,319		$	8,662		$	—	$	44,985
										—
Investing Activities										—
Additions to property, plant and equipment	—			(77,674		)	(680		)	—		(78,354		)
Investment in short-term securities	—			(242,848		)	—			—		(242,848		)
Net cash used for investing activities	—			(320,522		)	(680		)	—		(321,202		)

Financing Activities
Proceeds from issuance of senior unsecured notes	300,000			—			—			—		300,000
Payment of debt issuance costs	(8,221		)	—			—			—		(8,221		)
Proceeds from stock option exercises	200			—			—			—		200
Tax benefit of stock option exercises	17			—			—			—		17
Distribution to minority stockholders	—			5,489			(7,000		)	—		(1,511		)
Net cash provided by (used for) financing activities	291,996			5,489			(7,000		)	—		290,485
Net increase/(decrease) in cash and cash equivalents	—			13,286			982			—		14,268
Cash and cash equivalents at beginning of period	—			26,413			3,378			—		29,791
Cash and cash equivalents at end of period	$	—		$	39,699		$	4,360		$	—	$	44,059

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

This report contains forward-looking statements made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements include all statements that do not relate solely to current or historical fact, but address events or developments that we anticipate will occur in the future. Forward-looking statements include statements regarding our goals, beliefs, plans or current expectations, taking into account the information currently available to our management. When we use words such as “anticipate,” “intend,” “expect,” “believe,” “plan,” “may,” “should” or “would” or other words that convey uncertainty of future events or outcome, we are making forward-looking statements. Statements relating to future sales, earnings, operating performance, restructuring strategies, 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 six month periods ended June 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 ethanol and from the sale of co-products (corn gluten feed and meal, corn germ, condensed corn distillers solubles, DDGS, WDGS, carbon dioxide, and brewers’ yeast) that we produce as by-products during the production of ethanol at our plants, which we refer to as co-product revenues. We sell ethanol obtained from the following sources:

· Ethanol we manufacture at our plants;

· Ethanol we purchase from our marketing alliance partners; and

· Ethanol we purchase on the spot market.

We market and sell ethanol without regard to whether we produced it, are marketing it for our marketing alliance partners or purchased it on the spot market for resale. In addition to ethanol, we also purchase and market biodiesel.

Executive Summary

We generated net income of $12.6 million, or $0.30 per diluted share in the second quarter of 2007, as compared to net income of $24.7 million, or $0.67 per diluted share, in the second quarter of 2006. Net income decreased primarily as a result of significantly higher corn costs combined with lower ethanol revenue per gallon sold. Second quarter 2006 results benefited from the sale of 10.5 million gallons of ethanol from inventory at prices significantly higher than their first quarter 2006 weighted average cost of $1.58 per gallon, increasing gross profit in the second quarter of 2006 by approximately $18.6 million. 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 second quarter of 2007 was $394.9 million, a decrease of $48.0 million, or 10.8%, over second quarter 2006 revenue of $442.9 million. The decrease is mainly the result of a decrease in gallons sold, as VeraSun Energy Corporation was no longer part of our marketing alliance, along with a reduction in the average price per gallon of ethanol sold. The average sales price per gallon of ethanol in the second quarter of 2007 was $2.29 per gallon, down from $2.41 per gallon in the same quarter in 2006.

Gallons of ethanol sold in the second quarter of 2007 decreased 10.0% to 158.7 million gallons, as compared to 176.3 million gallons in the second quarter of 2006. Ethanol sales for the quarter decreased as a result of lower marketing alliance purchases due to a former alliance member leaving our marketing alliance on April 1, 2007. The lower number of marketing alliance gallons purchased was offset somewhat by increased equity production. Ethanol production in the quarter totaled 50.7 million gallons, up from 28.9 million gallons in the second quarter of 2006. This record production was achieved despite some operational issues at the Aurora facility.

Gross profit totaled $27.4 million in the second quarter of 2007, a decrease of $22.8 million, or 45.4%, from the second quarter of 2006. The decline in gross profit was principally the result of a significantly lower commodity spread caused by higher corn prices and lower ethanol prices. Our corn costs during the second quarter of 2007 averaged $3.99 per bushel, significantly higher than our second quarter 2006 cost of $2.27 per bushel.

The average cost of inventory was $1.98 at the end of the second quarter of 2007 as compared to $1.91 at the end of the first quarter of 2007. The average cost per gallon of ethanol purchased in the second quarter of 2007 was higher than in the first quarter of 2007. This means that the lower per gallon value of ethanol in inventory at the end of the first quarter of 2007 positively impacted gross margin during the second quarter by $2.1 million. This compares with the same issue positively impacting gross margin in the second quarter of 2006 by approximately $18.6 million, as the second quarter 2006 average

cost of inventory was $2.19 per gallon as compared to $1.58 per gallon at the end of the first 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 income for the second quarter of 2007 includes $2.1 million of realized and unrealized gains on corn derivative contracts and from 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 June 30, 2007. Increases in prices for open derivative contracts above the closing price at June 30, 2007 will result in mark to market losses on these positions, while prices lower than those at June 30, 2007 will allow for additional hedge gains.

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

Total gallons sold in the second quarter of 2007 were 158.7 million gallons, versus 176.3 million gallons sold in the second quarter of 2006, a decrease of 17.6 million gallons or 10.0%. Gallons sourced were as follows:

For the Three Months Ended June 30,
*(In thousands, except for percentages)*	2007	2006	Increase/ (Decrease)		% Increase/ (Decrease)
Equity production	50,679	28,902	21,777		75.3	%
Marketing alliance purchases	75,105	120,156	(45,051	)	(37.5	)%
Purchase/resale	22,085	16,701	5,384		32.2	%
Decrease/(increase) in inventory	10,862	10,508	354		N.M.*
Total	158,731	176,267	(17,536	)	(9.9	)%

* Not meaningful

Net sales in the second quarter of 2007 decreased 10.8% from the second quarter of 2006. Net sales were $394.9 million in the second quarter of 2007 versus $442.9 million in the second quarter of 2006. Overall, the decrease in net sales was a combination of a decrease in the number of gallons sold and a decrease in the average sales price of ethanol. Gallons sold in the second quarter of 2007 declined as a result of a lower number of gallons that were purchased from marketing alliance partners as a result of the departure of a marketing alliance partner from our alliance on April 1, 2007. The average gross selling price of ethanol in the second quarter of 2007 was $2.29 per gallon, down from the $2.41 received in the second quarter of 2006.

Co-product revenue for the second quarter of 2007 totaled $23.2 million, an increase of $11.5 million or 98.3%, from the second quarter 2006 total of $11.7 million. Co-product revenue increased during the second quarter of 2007 principally from an increase in co-product tonnage sold as a result of the DDGS produced from the new Pekin dry mill production, along with higher average selling prices. In the second quarter of 2007, we sold 297.1 thousand tons, versus 200.4 thousand tons in the second quarter of 2006. Co-product returns, as a percentage of the price of corn, were 31.1% during the second quarter of 2007, versus 46.2% in the second quarter of 2006. Co-product returns, as a percentage of the price of corn, decreased in the second quarter of 2007 as compared to 2006 as the result of the mix of co-products produced, with the addition of the new Pekin dry mill, and as a result of co-product pricing not keeping pace with the year over year increase in the price of corn. 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 June 30, 2007 was $367.5 million, compared to $392.7 million for the quarter ended June 30, 2006, a decrease of $25.2 million or 6.4%. 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 from unaffiliated producers and marketers, freight and logistics costs 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 purchased ethanol costs, and higher corn and production costs.

Purchased ethanol in the second quarter of 2007 totaled $207.9 million, versus $314.5 million in the second 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 second quarter of 2007, we purchased 97.2 million gallons of ethanol at an average cost of $2.14 per gallon as compared to 136.9 million gallons of ethanol at an average cost of $2.30 in the second 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 second quarter of 2007 totaled $74.7 million or $3.99 per bushel, versus $25.3 million, or $2.27 per bushel in the second quarter of 2006. The increase in corn costs is principally the result of a perceived increased demand by the marketplace as a result of expected new ethanol production facilities being built. Conversion costs for the second quarter of 2007 increased to $30.9 million from $22.9 million for the second quarter of 2006. The total dollars spent on conversion costs increased year over year as a result of the new Pekin dry mill production. However, the conversion cost per gallon declined year over year to $0.61 per gallon in the second quarter of 2007 versus $0.79 per gallon in the second quarter of 2006. Conversion costs per gallon in the second quarter of 2006 were negatively affected by lower production caused by maintenance outages at both production facilities along with production issues at the Aurora, Nebraska facility.

Depreciation in the second quarter of 2007 totaled $3.0 million, versus $1.1 million in the second quarter of 2006. The increase in depreciation expense is the result of the new Pekin dry mill beginning production. Motor fuel taxes were $4.3 million in the second quarter of 2007 versus $4.0 million in the second quarter of 2006. The cost of motor fuel taxes are recovered through billings to customers.

Freight/logistics costs in the second quarter of 2007 decreased to $28.0 million, or approximately $0.18 per gallon, from $29.6 million, or $0.17 per gallon in the second 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 may also include costs to ship co-products. The increase in freight/logistics cost per gallon is principally the result of a reduced number of gallon shipped over which to spread fixed costs, and from the expansion of our distribution system footprint.

The average cost of inventory was $1.98 at the end of the second quarter of 2007 as compared to $1.91 at the end of the first quarter of 2007. The average cost per gallon of ethanol purchased in the second quarter was higher than in the first quarter. This means that the lower per gallon value of ethanol in inventory at the end of the first quarter positively impacted gross margin during the second quarter by $2.1 million. In 2006, the average cost of inventory was $2.19 at the end of the second quarter as compared to $1.58 at the end of the first quarter of 2006. Because the average cost per gallon of ethanol

purchased in the second quarter of 2006 was higher than in the first quarter of 2006, the lower per gallon value of ethanol in inventory at the end of the first quarter positively impacted gross margin during the second quarter by approximately $18.6 million.

Selling, general and administrative expenses (“SG&A”) expenses were $8.8 million in the second quarter of 2007, compared to $7.4 million in the second quarter of 2006. The increase in SG&A expenses include 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 increased legal fees related to our capacity expansion efforts, the costs of complying with Section 404 of Sarbanes-Oxley Act of 2002, higher insurance costs related to directors and officers insurance, and increased IT costs.

Interest income in the second quarter of 2007 was $4.2 million, versus $1.2 million in the second 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 second quarter of 2007 was $7.0 million, as compared to $4.2 million in the second quarter of 2006. Interest expense in the second quarter of 2007 increased due to the issuance in March 2007 of $300 million aggregate principal amount of 10.0% senior unsecured notes. In the second quarter of 2006, we had outstanding a previous issue of $160 million aggregate principal amount of floating rate senior secured notes, the majority of which was repurchased in July 2006.

The minority interest for the quarter ended June 30, 2007 was a $0.7 million charge to income compared to $1.7 million charge to income for the quarter ended June 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 second quarter of 2007 from the sale of ethanol.

Other non-operating income for the second quarter of 2007 includes $2.1 million of realized and unrealized gains on corn derivative contracts and from 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 second quarter of 2006, net realized and unrealized gains of $1.9 million were recorded on corn derivative contracts. Other non-operating income is impacted by the CBOT prices for derivative contracts.

The income tax rate for the second quarter of 2007 was 28.9% versus a rate of 39.1% in the second quarter of 2006. The lower rate in the second quarter of 2007 resulted from lower state rates now being accrued as compared to the second quarter of 2006, along with adjusting our estimated tax provision for the second quarter of 2007 to reflect both a higher level of tax exempt interest income from investments and from a lower level of pre-tax income as compared to our first quarter of 2007 estimate. The true-up in the second quarter of 2007 adjusts our year to date 2007 rate to 32.5%, which is what we now estimate we will incur for 2007. Income tax expense for the second quarter of 2007 also includes a component for interest expense related to uncertain tax positions in accordance with FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes- an interpretation of FASB Statement No. 109.

For the Six Months Ended June 30, 2007 Compared to the Six Months Ended June 30, 2006

Total gallons sold in the first six months of 2007 were 351.9 million gallons, versus 341.1 million gallons sold in the first six months of 2006, an increase of 10.8 million gallons or 3.2%. Gallons sourced were as follows:

For the Six Months Ended June 30,
*(In thousands, except for percentages)*	2007		2006	Increase/ (Decrease)		% Increase/ (Decrease)
Equity production	99,586		65,578	34,008		51.9	%
Marketing alliance purchases	209,814		240,768	(30,954	)	(12.9	)%
Purchase/resale	43,613		31,125	12,488		40.1	%
Decrease/(increase) in inventory	(1,094	)	3,649	4,743		N.M.*
Total	351,919		341,120	20,285		5.9	%

* Not meaningful

Net sales in the first half of 2007 increased 9.9% from the first half of 2006. Net sales were $831.6 million in the first half of 2007 versus $756.4 million in the first half of 2006. Overall, the increase in net sales was a combination of the increase in the number of gallons sold and the increase in the average sales price of ethanol. Gallons sold in the first six months of 2007 increased as a result of a higher equity production and a higher number of gallons purchased from non-affiliated producers offset by the lower number of gallons that were purchased from marketing alliance partners as a result of a marketing alliance partner who left our marketing alliance as of April 1, 2007. The average gross selling price of ethanol in the first half of 2007 increased to $2.18 per gallon, from the $2.11 received in the first half of 2006.

Co-product revenue for the first six months of 2007 totaled $46.3 million, an increase of $19.8 million or 74.7%, from the first six month 2006 total of $26.5 million. Co-product revenue increased during the first six 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 and production issues in 2006, along with higher average selling prices. In the first six months of 2007, we sold 564.1 thousand tons, versus 448.8 thousand tons in the first six months of 2006. Co-product returns, as a percentage of the price of corn, were 33.2% during the first half of 2007, versus 48.1% in the first half of 2006. Co-product returns, as a percentage of the price of corn, decreased in the first half 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 six months of 2007 was $775.7 million, compared to $675.6 million for the first six months of 2006, an increase of $100.1 million or 14.8%. 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 from unaffiliated producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers. The increase in cost of goods sold is principally the result of the increased number of ethanol gallons purchased from non-affiliated producers and marketers, and from higher purchased ethanol costs and higher corn and production costs.

Purchased ethanol in the first half of 2007 totaled $508.7 million, versus $536.2 million in the first six months of 2006. The decrease in purchased ethanol results from a decrease in the number of gallons of ethanol purchased, offset by an increase in the cost per gallon of ethanol purchased. In the first half of 2007, we purchased 253.4 million gallons of ethanol at an average cost of $2.01 per gallon as compared to 271.9 million gallons of ethanol at an average cost of $1.97 in the first half of 2006.

other miscellaneous production costs) and depreciation and amortization. Corn costs in the first half of 2007 totaled $139.4 million or $3.79 per bushel, versus $54.5 million, or $2.19 per bushel in the first half of 2006. The increase in corn costs is principally the result of a perceived increased demand by the marketplace as a result of expected new ethanol production facilities being built. Conversion costs for the first half of 2007 increased to $57.9 million from $43.5 million for the first half of 2006. The total dollars spent on conversion costs increased year over year as a result of the new Pekin dry mill production. However, the conversion cost per gallon declined year over year to $0.58 per gallon in the first half of 2007 versus $0.66 per gallon in the first half of 2006. Conversion costs per gallon in the first half of 2006 were negatively affected by lower production caused by maintenance outages at both production facilities along with production issues at the Aurora, Nebraska facility.

Depreciation in the first half of 2007 totaled $6.0 million, versus $2.1 million in the first half of 2006. The increase in depreciation expense is the result of the new Pekin dry mill beginning production. Motor fuel taxes were $10.5 million in the first half of 2007 versus $5.6 million in the first half of 2006. The cost of motor fuel taxes are recovered through billings to customers.

Freight/logistics costs in the first half of 2007 increased to $58.2 million, or approximately $0.17 per gallon, from $52.0 million, or $0.15 per gallon in the first half of 2006. The increase in freight/logistics cost is principally the result of a reduced number of gallons shipped over which to spread fixed costs, and from the expansion of our distribution system footprint.

The average cost of inventory was $2.19 at the end of the second quarter of 2006 as compared to $1.58 at the end of the first quarter of 2006. The average cost per gallon of ethanol purchased in the second quarter was higher than in the first quarter. This means that the lower per gallon value of ethanol in inventory at the end of the first quarter positively impacted gross margin during the second quarter by approximately $18.6 million.

SG&A expenses were $18.4 million in the first half of 2007, compared to $13.6 million in the first half 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 in SG&A costs are primarily due to increased costs related to legal and other professional fees associated with our being a public company, including increased legal fees related to our capacity expansion efforts, the costs of complying with Section 404 of Sarbanes-Oxley Act of 2002, higher insurance costs related to directors and officers insurance, and increased IT costs.

Interest income in the first half of 2007 was $5.5 million, versus $1.9 million in the first half 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 half of 2007 was $7.4 million, as compared to $8.6 million in the first half of 2006. Interest expense in the first half of 2007 reflects only interest incurred from March 2007 through June 2007 on our $300 million aggregate principal amount of 10.0% senior unsecured notes. In the first half of 2006, we had outstanding a previous issue of $160 million aggregate principal amount of floating rate senior secured notes for the entire first half of 2006, the majority of which was repurchased in July 2006.

The minority interest for the first half of 2007 was a $1.2 million charge to income compared to $2.9 million charge to income for the first half 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 offset somewhat by the higher average price received per gallon in the first half of 2007 as compared to 2006 from the sale of ethanol.

Other non-operating income for the first half of 2007 of $6.0 million reflects realized and unrealized gains on corn derivative contracts and from realized and unrealized losses on the sale of forward gasoline contracts. These include the effect of marking to market these contracts at June 30, 2007. For the first half of 2006, we recognized $2.5 million of net realized and unrealized gains on corn derivative contracts. Other non-operating income is impacted by the CBOT prices for derivative contracts.

Income taxes for the first half of 2007 were accrued at a rate of 32.5% versus a rate of 39.3% in the first half of 2006. The lower rate in the first half of 2007 results from lower state rates being accrued as compared to the first half of 2006, along with a higher level of tax exempt interest income from investments and a lower level of pre-tax income as compared to our 2006 estimate. We expect our estimated tax rate for 2007 to be approximately 32.5%. Income tax expense for the first six months of 2007 also includes a component for interest expense related to uncertain tax positions in accordance with FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes- an interpretation of FASB Statement No. 109.

Trends and Factors that May Affect Future Operating Results

Ethanol Pricing

As of June 30, 2007, we had contracts for delivery of ethanol totaling 161.7 million gallons for delivery throughout the remainder of 2007, which represents approximately 57% of our expected ethanol shipments for the remainder of the year. These commitments were for 20.7 million gallons at an average fixed price of $2.05, 49.7 million gallons at an average positive spread to wholesale gasoline of $0.03 (based upon the NYMEX, Chicago and NY harbor indices), and 91.3 million gallons at spot prices (using various Platt, OPIS and AXXIS indices). Although these contracts are for delivery throughout 2007, they are heavily weighted towards the third quarter of 2007. In the second quarter of 2007, we also took short gasoline positions through swap agreements where we sold 15.2 million gallons of gasoline at a fixed price of $1.96 per gallon for delivery from August 2007 through January 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 June 30, 2007 was a loss of approximately $1.5 million.

Corn Pricing

Based on our current hedges and current market conditions, we estimate our corn costs for the third quarter of 2007 will be in the $3.75 to $3.85 per bushel range, and our fourth quarter 2007 corn costs will be in the $3.40 to $3.50 per bushel range, excluding any effects of mark to market adjustments on our hedge positions. All of our corn hedge positions have been marked to market, and we have already recorded income or loss with respect to these positions as of June 30, 2007. Increases in prices for open derivative contracts above the closing price at June 30, 2007 will result in mark to market losses on these positions, while prices lower than those at June 30, 2007 will allow for additional hedge gains.

Marketing Alliance

As of April 1, 2007, VeraSun Energy Corporation was no longer part of our marketing alliance. During the second quarter, two new marketing alliance partner projects began ethanol production. E3 Biofuels, with production capacity of 24 million gallons of ethanol annually, and Redfield Energy, LLC, with production capacity of 50 million gallons of ethanol annually, both began shipping product during

the second quarter. As of June 30, 2007, our marketing alliance partners have nameplate capacity to produce 361 million gallons of ethanol annually. We expect one more new plant with annual capacity of 50 million gallons to come online in 2007, along with the expansion of one existing plant to also add 50 million gallons of annual capacity. We have also signed contracts to market an additional 1.4 billion gallons of ethanol from existing and new marketing alliance partners who have projects currently under construction, and for projects which have been proposed. 301 million gallons of this amount is currently under construction. We believe these plants currently under construction will be completed and we expect to market these additional gallons. These plants are expected to come online between October 2007 and December 2008. In addition, we have also signed marketing agreements for another 1.1 billion gallons of annual capacity for proposed projects. 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 decrease, 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 committed to build new ethanol production facilities at Mt. Vernon, Indiana and Aurora, Nebraska, and are exploring adding additional capacity at our existing Pekin, Illinois campus.

We intend to substantially complete 226 million gallons of capacity expansions by the end of 2008. The timing of the remaining expansions will be based upon, among other factors, market conditions and the availability of financing on attractive terms. On May 31, 2007, we entered into separate but substantially identical EPC contracts with a construction firm, Kiewit Energy Company (“Kiewit”), to build two initial 113 million gallon ethanol production facilities in Mount Vernon, Indiana and Aurora, Nebraska. Delta-T Corporation is the technology provider and is a sub-contractor to Kiewit under the EPC contracts. Under the terms of each of the EPC contracts, Kiewit will provide certain EPC materials and services necessary to build ethanol production facilities at each site capable of initially producing 113 million gallons of denatured ethanol annually as the primary product. In addition, 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 plants, and the Company is currently seeking permits for the full 226 million gallons of annual production capacity for each site upfront. The 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. These costs are the responsibility of Aventine.

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. Our timetable to begin and complete these projects is subject to numerous factors beyond our control. In particular, we have not yet received any environmental or other permits with respect to these expansions (although construction and certain 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 second quarter of 2007, we announced the addition of a major new biodiesel producer to our biodiesel marketing effort. In the second quarter of 2007, we sold 1.9 million gallons of biodiesel. Although this program is still in its infancy, 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)	June 30, 2007 (Unaudited)		December 31, 2006

Cash and cash equivalents	$	44,059	$	29,791
Short-term investments	341,773		98,925
Working capital	454,768		203,247
Total debt	300,000		—
Current ratio	7.90		3.44

On May 31, 2007, we entered 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. These costs are the responsibility of Aventine. 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 plants, and the Company is currently seeking permits for the full 226 million gallons of annual production capacity for each site upfront. 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 (using commercially reasonable best efforts to obtain a permit for 226 million gallon capacity) 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 226 million gallon 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. Notwithstanding the above, if, despite our diligent efforts, we are unable to obtain permits for the Mt. Vernon facility by September 1, 2007, we have agreed to negotiate in good faith a waiver of the compliance date and establish a new date for compliance. If we do not reach an agreement, either the Mount Vernon lessor or we can terminate the Mount Vernon lease. Accordingly, we cannot estimate the amount of damages we could be liable for.

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.

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 six months of 2007, cash and short-term investments increased by $257.1 million. Cash and short-term investments as of June 30, 2007 and December 31, 2006 were $385.8 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, cash received from our initial public offering completed in the third quarter of 2006, and from cash provided by operations.

Cash provided by operations. Net cash provided by operating activities in the first six months of 2007 was $45.0 million, as compared to cash provided by operating activities of $43.5 million for the first six months of 2006. The increase in cash provided by operations in 2007 versus 2006 is primarily the result of accounts receivable decreasing at a faster rate than our accounts payable, due to the lower working capital requirements necessary to support ethanol purchases from the marketing alliance partner who left our marketing alliance on April 1, 2007. Cash on our balance sheet, along with the cash received from the issuance of the $300 million of 10% senior unsecured notes, along with continued strong pricing and demand for ethanol, 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. We had no borrowings outstanding under our secured revolving credit facility at June 30, 2007 and $1.2 million of standby letters of credit outstanding, leaving approximately $70.8 million in additional borrowing availability thereunder as of that date. 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. A fixed asset component in an amount of $50 million may be added to the borrowing base under our new senior secured revolving liquidity facility on or prior to December 31, 2007 upon the satisfaction of certain requirements. We are

in the process of satisfying the requirements necessary in order to take advantage of this fixed asset component.

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 six months of 2007, capital expenditures (excluding expansion related expenditures) totaled $8.7 million versus $5.1 million in the first six 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 between $20 and $22 million.

Capital expenditures related to our announced expansion projects totaled $69.7 million in the first six months of 2007. Amounts spent on the Aurora West and Mt. Vernon include the pre-purchasing of long lead-time equipment and stainless steel material, licensing fees and site preparation work in anticipation of receiving environmental permits. We expect to spend approximately $250 million in total during 2007 on capacity related expenditures.

Payments related to our outstanding debt and liquidity facility. In the first six months of 2007, we did not make any interest payments on our debt or our liquidity facility. In the first six months of 2006, we paid $8.7 million in interest payments on our debt and liquidity facility.

Repurchase of shares of common stock. In the first six months of 2007, we did not repurchase any shares of our common stock under the share repurchase program approved by our Board of Directors. The share repurchase program allows the repurchase of up to $50 million of our outstanding common stock, although there are no minimum share purchase requirements. There is approximately $48.8 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 June 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. In addition, the permits ultimately issued may impose conditions which are more costly to implement than we had anticipated. These costs could have a material adverse affect on our financial condition and results of operations. Because other ethanol manufacturers in the U.S. are and will continue to be subject to similar laws and restrictions, we do not currently believe that our costs to comply with current or future environmental laws and regulations will adversely affect our competitive position 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. We have included in our capital budget for 2007 approximately $10.8 million for projects relating to environmental, health and safety matters, including for the installation of air pollution control equipment and for wastewater discharge improvements at our Illinois wet mill facility. As of June 30, 2007, we have spent approximately $2.1 million of this amount. The majority of the 2007 environmental capital budget relates to compliance with the EPA’s final National Emissions Standard for Hazardous Air

Pollutants, or NESHAP, under the federal Clean Air Act for industrial, commercial and institutional boilers and process heaters. This NESHAP 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 June 12, 2008 to complete work under this NESHAP. Based on engineering conducted to date and currently available information, we have budgeted $7.4 million to comply with this NESHAP in 2007. If we do not meet this June 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 Illinois and Nebraska facilities. New laws or regulations relating to the production, disposal or emissions of carbon dioxide may require us to incur significant additional costs and may also adversely affect our ability to continue generating revenue from carbon dioxide sales.

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 June 30, 2007 and 2006 was $3.99 and $2.27 per bushel, respectively. For the six month periods ended June 30, 2007 and 2006, our weighted average corn costs were $3.79 and $2.19 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 June 30, 2007, we had commitments to purchase approximately 18.0 million bushels of corn through December 2009 at an average price of $3.98 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)	June 30, 2007

Realized and unrealized gains included in earnings	$	3.7

(In millions)	June 30, 2007

Net bushels sold	12.5
Aggregate notional value of derivatives outstanding	$	48.6
Period through which derivative positions currently exist	December 2009
Unrealized gain on the fair value of outstanding derivative positions	$	4.7
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$	(4.4	)

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 June 30, 2007, we had fixed contracts to sell approximately 20.7 million gallons of ethanol at an average fixed price of $2.05 per gallon. 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 June 30, 2007, we had sold forward approximately 49.7 million gallons of ethanol using wholesale gasoline as an index plus a fixed spread that averaged $0.03 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 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)	June 30, 2007

Realized and unrealized loss included in earnings	$	(1.5	)

(In millions)	June 30, 2007

Gallons sold	15.2
Aggregate notional value of derivatives outstanding	$	29.8
Period through which derivative positions currently exist	January 2008
Unrealized loss on the fair value of outstanding derivative positions	$	(1.5	)
The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value	$	(3.1	)

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. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

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

None

Item 3. Defaults Upon Senior Securities

None

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

On May 9, 2007, the Company held its Annual Meeting of Stockholders. The matters voted on at the meeting and the results of those votes were as follows:

(1) Election of Class II Directors:

	Vote for	Votes against	Votes withheld and non-votes

Richard A. Derbes	33,589,889	1,168,669	7,142,186
Michael C. Hoffman	35,016,650	294,444	6,589,650
Arnold M. Nemirow	35,023,330	287,613	6,589,801

Other directors whose term of office continued after the meeting were Messrs. Bobby L. Latham as Class I directors; and Messrs. Leigh J. Abramson, Wayne D. Kuhn and Ronald H. Miller as class III directors.

(2) Ratification of the Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan (Amended and Restated as of March 22, 2007):

Vote for	Votes against	Votes withheld and non-votes

25,832,900	4,357,951	11,709,893

(3) Ratification of the appointment of Ernst and Young LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2007:

Vote for	Votes against	Votes withheld and non-votes

35,274,398	43,762	6,582,584

Item 5. Other Information

None

Item 6. Exhibits

(a) Exhibits

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

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

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

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

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

	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.

* Portions of the exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.

Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended June 30, 2007

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

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: August 10, 2007	By:	/s/ William J. Brennan
	Name:		William J. Brennan
	Title:		Principal Accounting Officer