UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2007

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File No. 1-32913

VeraSun Energy Corporation

(Exact name of registrant as specified in its charter)

South Dakota	20-3430241
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification Number)
100 22nd Avenue Brookings, SD	57006
(Address of principal executive offices)	(Zip Code)

605-696-7200

(Registrant’s telephone number, including area code)

NONE

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark 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  ¨    Accelerated filer  ¨    Non-accelerated filer  x

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

The number of shares of Common Stock outstanding on November 5, 2007 was 92,889,902.

VERASUN ENERGY CORPORATION

SEPTEMBER 30, 2007

INDEX TO FORM 10-Q

	PAGE NO.
PART I. FINANCIAL INFORMATION
Item 1 — Financial Statements
Condensed Consolidated Balance Sheets	3
Condensed Consolidated Statements of Operations	4
Condensed Consolidated Statements of Cash Flows	5
Notes to Condensed Consolidated Financial Statements	6
Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3 — Quantitative and Qualitative Disclosures About Market Risk	32
Item 4 — Controls and Procedures	35
PART II. OTHER INFORMATION
Item 1A — Risk Factors	35
Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6 — Exhibits	46
SIGNATURES	49

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VERASUN ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	September 30, 2007			December 31, 2006
	(unaudited)
Assets
Current Assets
Cash and cash equivalents	$	320,220		$	318,049
Receivables		65,477			62,549
Inventories		71,522			39,049
Prepaid expenses		7,927			4,187
Derivative financial instruments		—			12,382
Total current assets		465,146			436,216
Restricted cash held in escrow		—			44,267
Debt issuance costs, net		22,765			5,685
Goodwill		198,585			6,129
Other long-term assets		6,976			480
		228,326			56,561
Property and equipment, net		1,083,034			301,720
	$	1,776,506		$	794,497
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	235		$	—
Current portion of deferred revenues		95			96
Accounts payable		54,423			36,391
Accrued expenses		52,327			2,961
Derivative financial instruments		820			11,331
Deferred income taxes		1,803			1,370
Total current liabilities		109,703			52,149
Long-term debt, less current maturities		879,020			208,905
Deferred revenues, less current portion		1,543			1,613
Deferred income taxes		36,448			25,399
		917,011			235,917
Commitments and Contingencies
Shareholders’ Equity
Common stock, $0.01 par value; authorized 250,000,000 shares; 92,799,771 and 75,463,640 shares issued and outstanding as of September 30, 2007 and December 31, 2006, respectively		928			755
Additional paid-in capital		636,758			417,049
Retained earnings		112,206			89,589
Accumulated other comprehensive loss		(100	)		(962	)
		749,792			506,431
	$	1,776,506		$	794,497

See accompanying notes to condensed consolidated financial statements.

3

VERASUN ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands, except per share data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Revenues:
Net sales	$	220,734		$	147,392		$	533,363		$	409,581
Other revenues, incentive income		1,134			857			2,571			3,076
Total revenues		221,868			148,249			535,934			412,657
Cost of goods sold		198,474			88,654			470,811			260,780
Gross profit		23,394			59,595			65,123			151,877
Startup expenses		1,675			235			3,257			541
Selling, general and administrative expenses		9,862			7,189			28,211			33,065
Operating income		11,857			52,171			33,655			118,271
Other income (expense):
Interest expense, including change in fair value of convertible put warrant in 2006		(12,016	)		(4,446	)		(19,947	)		(34,508	)
Interest income		5,523			4,981			14,430			8,951
Other income		4			2,670			36			2,691
		(6,489	)		3,205			(5,481	)		(22,866	)
Income before income taxes		5,368			55,376			28,174			95,405
Income tax provision (benefit)		(2,425	)		23,376			5,557			41,117
Net income	$	7,793		$	32,000		$	22,617		$	54,288
Per share data:
Income per common share—basic	$	0.09		$	0.43		$	0.29		$	0.81
Basic weighted average number of common shares		85,177,689			74,908,467			79,329,665			67,428,927
Income per common share—diluted	$	0.09		$	0.40		$	0.27		$	0.76
Diluted weighted average number of common and common equivalent shares		88,157,051			79,837,314			83,472,558			71,339,291

See accompanying notes to condensed consolidated financial statements.

4

VERASUN ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

(Unaudited)

	Nine Months Ended September 30,
	2007			2006
	(dollars in thousands)
Cash Flows from Operating Activities
Net income	$	22,617		$	54,288
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		11,120			7,165
Amortization of debt issuance costs and debt discount		1,357			980
Accretion of deferred revenue		(71	)		(71	)
Change in fair value of convertible put warrant		—			19,670
Change in derivative financial instruments		3,198			(3,046	)
Deferred income taxes		11,017			10,810
(Gain) loss on disposal of equipment		(82	)		30
Stock-based compensation expense		4,356			21,008
Excess tax benefits from share-based payment arrangements		(8,424	)		(17	)
Changes in current assets and liabilities, net of affects of business acquisition:
(Increase) decrease in:
Receivables		(2,928	)		2,076
Inventories		(29,193	)		3,052
Prepaid expenses		(3,335	)		2,124
Increase (decrease) in:
Accounts payable		39,476			(10,692	)
Accrued expenses		24,538			9,995
Net cash provided by operating activities		73,646			117,372
Cash Flows from Investing Activities
Investment in restricted cash		—			(1,631	)
Purchases of property and equipment		(303,241	)		(15,626	)
Payment for other long-term assets		(6,496	)		—
ASA Acquisition		(242,775	)		—
Proceeds from sale of equipment		6			838
Net cash used in investing activities		(552,506	)		(16,419	)
Cash Flows from Financing Activities
Proceeds from long-term debt		471,367			—
Proceeds from the issuance of 2,934,747 and 12,754,825 shares of common stock, respectively		12,784			233,135
Excess tax benefits from share-based payment arrangements		8,424			17
Costs of raising capital		(5	)		—
Debt issuance costs paid		(11,539	)		(1,173	)
Net cash provided by financing activities		481,031			231,979
Net increase in cash and cash equivalents		2,171			332,932
Cash and Cash Equivalents
Beginning		318,049			29,714
Ending	$	320,220		$	362,646

See accompanying notes to condensed consolidated financial statements.

5

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(dollars in thousands, except per share data)

Note 1. Unaudited Interim Condensed Consolidated Financial Statements

The accompanying condensed consolidated balance sheet as of December 31, 2006 has been derived from audited consolidated financial statements. The unaudited interim condensed consolidated financial statements of VeraSun Energy Corporation and its subsidiaries reflect all adjustments consisting only of normal recurring adjustments that are, in the opinion of our management, necessary for a fair presentation of their consolidated financial position and results of operations and cash flows. The results for the three and nine months ended September 30, 2007 are not necessarily indicative of the results that may be expected for a full fiscal year. Certain information and note disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), although the Company believes that the disclosures made are adequate to make the information not misleading. These condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in its annual report for the year ended December 31, 2006 filed on Form 10-K with the SEC. VeraSun Energy Corporation and its subsidiaries are collectively referred to as “VeraSun,” the “Company,” “we,” “us” and “our”.

Nature of Business

VeraSun is one of the largest ethanol producers in the United States based on production capacity, according to the Renewable Fuels Association (“RFA”). We focus primarily on the production and sale of ethanol and its co-products.

Principles of Consolidation

The accompanying condensed consolidated financial statements include the accounts of VeraSun Energy Corporation and its subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.

Reclassifications

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

Revenue Recognition

We recognize revenue when all of the following criteria are satisfied: persuasive evidence of an arrangement exists; risk of loss and title transfer to the customer; the price is fixed and determinable; and collectability is reasonably assured. Sales and related costs of goods sold are included in income upon delivery to our customers at terminals or other locations, except sales to Cargill, Incorporated and its affiliates (“Cargill”) from our Linden, Indiana and Albion, Nebraska facilities, where sales of ethanol and co-products are recognized upon shipment from the plants. Generally, there are no formal customer acceptance requirements or further obligations relating to our products. If such requirements or obligations exist, we recognize the related revenues when the requirements are completed and the obligations are fulfilled. Shipping and handling charges to customers are included in revenue, including shipping and handling charges incurred on our behalf for product marketed by Cargill.

We receive incentives to produce ethanol from state and federal entities. In accordance with the terms of these arrangements, incentive income is recognized when we produce ethanol or blend ethanol with gasoline to produce E85.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect (i) the reported amounts of assets and liabilities, (ii) the disclosure of contingent assets and liabilities at the date of the financial statements, and (iii) the reported amounts of revenues and expenses during the reporting period.

6

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

We use estimates and assumptions in accounting for the following significant matters, among others:

• Allowances for doubtful accounts

• Valuation of acquired assets

• Inventory valuation and allowances

• Fair value of derivative instruments and related hedged items

• Useful lives of property and equipment and intangible assets

• Asset retirement obligations

• Long-lived asset impairments, including goodwill

• Contingencies

• Fair value of options and restricted stock granted under our stock-based compensation plans

• Tax related items

Actual results may differ from previously estimated amounts, and such differences may be material to our condensed consolidated financial statements. We periodically review estimates and assumptions, and the effects of revisions are reflected in the period in which the revision is made. The revisions to estimates or assumptions during the periods presented in the accompanying condensed consolidated financial statements were not considered to be significant.

Startup Expenses

Costs associated with the operation of a facility prior to the production and sale of ethanol are expensed as incurred. For the three months ended September 30, 2007, we incurred startup expenses relating to the Albion, Nebraska; Hartley, Iowa; Bloomingburg, Ohio; Welcome, Minnesota; and Reynolds, Indiana facilities. For the three months ended September 30, 2006, the startup expenses pertained to the Charles City, Iowa facility. For the nine months ended September 30, 2007, we incurred startup expenses relating to the Charles City, Iowa; Albion, Nebraska; Hartley, Iowa; Bloomingburg, Ohio; Welcome, Minnesota; and Reynolds, Indiana facilities. For the nine months ended September 30, 2006, the startup expenses pertained to the Charles City, Iowa facility.

Recent Events

On October 1, 2007, the Company issued a press release announcing that it was suspending construction of its 110 million gallons per year ethanol biorefinery in Reynolds, Indiana, due to market conditions. See Note 11.

On August 17, 2007, we acquired certain facilities from ASAlliances Biofuels, LLC (“ASAlliances”). See Note 2.

On April 1, 2007, we began marketing and selling our ethanol to customers directly. In connection with this activity, we have established our own marketing, transportation and storage infrastructure. We lease tanker railcars and have contracted with storage depots near our customers and at other strategic locations for efficient delivery of our ethanol. We have also hired a marketing and sales force, as well as logistical and other operational personnel to staff our distribution activities. The termination of our relationship with Aventine Renewable Energy Holdings, Inc. (“Aventine”), which previously provided marketing and sales services, changed our customer base. For the nine months ended September 30, 2007, sales to each of Aventine and BP Products North America, Inc. exceeded 10% of net sales and on a combined basis represented 38.7% of net sales. For the three months ended September 30, 2007, sales to each of BP Products North America, Inc. and Shell Trading (US) Company, exceeded 10% of net sales and on a combined basis represented 33.5% of net sales.

Note 2. Acquisition

On August 17, 2007, we closed on a transaction with ASAlliances. Under a Unit Purchase Agreement, we purchased all of the equity interests in ASA OpCo Holdings, LLC (“ASA Holdings”) from ASAlliances for an aggregate purchase price of $675,176. Of this amount, we issued 13,801,384 shares of our common stock valued at $194,323, and paid $250,000 of cash to the seller at closing. The balance of the purchase price consisted of $230,853 of indebtedness owed by ASA Holdings and its subsidiaries, ASA Albion, LLC, ASA Bloomingburg, LLC and ASA Linden, LLC, which remained outstanding after the closing under a Credit Agreement, dated February 6, 2006 among ASA Holdings, ASA Albion, LLC, ASA Bloomingburg, LLC and ASA Linden, LLC, as borrowers, and WestLB AG, New York branch, as administrative agent for the lenders and the lenders named therein (“Senior Credit Facility”). We also agreed to register under applicable securities laws, within 180 days of the acquisition date, the shares issued in the transaction. ASA Holdings owns companies with three biorefineries and developmental rights to two sites. This transaction is referred to in this document as the “ASA Acquisition”.

7

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

The three acquired facilities are each expected to operate at 110 million gallons per year and are located in Albion, Nebraska, Bloomingburg, Ohio, and Linden, Indiana. This transaction allowed the Company to expedite its expansion in the ethanol market as the plants were near completion. The Linden facility began operations in August 2007 and the Albion facility began startup operations in October 2007. The Bloomingburg facility is expected to start up by the end of first quarter 2008.

The acquired assets of the ASA Acquisition have been included in the condensed consolidated balance sheet as of September 30, 2007 and operations of ASA Holdings are included in the Company’s condensed consolidated statement of operations beginning August 17, 2007.

The 13,801,384 shares of common stock issued in connection with the ASA Acquisition were valued at $194,323 based on the weighted average of the Company’s stock price two days before and two days after July 22, 2007, the date of the acquisition agreement and announcement of the transaction.

The following table provides unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2006 and 2007, as though the ASA Acquisition had occurred as of the beginning of the respective periods. The pro forma results include certain purchase accounting adjustments with respect to the acquired tangible and intangible assets. However, pro forma results do not include any anticipated costs savings or other effects of the planned integration of ASA Holdings. Accordingly, such amounts are not necessarily indicative of the results if the acquisition had occurred on the dates indicated or that may result in the future.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Pro forma results:
Net sales	$	221,868	$	148,249	$	535,934	$	412,657
Net income		5,614		30,853		18,138		49,832
Diluted earnings per common share		0.06		0.33		0.19		0.59

We are in the process of finalizing the allocation of the purchase price to the individual assets acquired and liabilities assumed. The preliminary allocation of the purchase price included in the current period condensed consolidated balance sheet is based on the estimates of management. The completion of the purchase price allocation may result in adjustments to the carrying value of ASA Holdings recorded assets and liabilities, revisions of the useful lives of intangible assets and the determination of any residual amount that will be allocated to goodwill. Goodwill is expected to be fully deductible for tax purposes. The related depreciation and amortization expense from the acquired assets is also subject to revision based on the final allocation. The following table presents the preliminary allocations as of the date of the acquisition.

Current assets	$	10,840
Property and equipment		465,132
Goodwill		192,456
Intangible assets		6,678
Other noncurrent assets		70
Total assets acquired		675,176
Current liabilities		32,090
Noncurrent liabilities		198,763
Total liabilities assumed		230,853
Net assets acquired	$	444,323

8

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

As part of the ASA Acquisition, we acquired the Linden, Albion and Bloomingburg facilities subject to long-term agreements with Cargill, under which Cargill is responsible for supplying all corn and natural gas to the facilities, providing commodities risk management services, and marketing all of the ethanol and distillers grains produced at the facilities. Generally, these agreements have ten year terms, except the corn supply agreement which has a twenty year term, and provide for the purchase and sale of commodities and products between the parties at market prices, and the payment of specified fees to Cargill.

Note 3. Inventories

A summary of inventories is as follows:

	September 30, 2007		December 31, 2006
Corn	$	14,072	$	24,492
Supplies		10,449		7,084
Chemicals		3,085		1,214
Work in process		5,011		2,489
Distillers grains		2,059		431
Ethanol		36,846		3,339
	$	71,522	$	39,049

Note 4. Earnings Per Common Share

Basic earnings per common share (“EPS”) is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that would occur, using the treasury stock method, if securities or other obligations to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that shared in the Company’s earnings.

A reconciliation of net income and common stock share amounts used in the calculation of basic and diluted EPS for the three months ended September 30, 2007 and 2006 follows:

	Net Income		Weighted Average Shares Outstanding	Per Share Amount
2007:
Basic EPS	$	7,793	85,177,689	$	0.09
Effects of dilutive securities:
Exercise of stock options, restricted stock and warrants		—	2,979,362		—
Diluted EPS	$	7,793	88,157,051	$	0.09
2006:
Basic EPS	$	32,000	74,908,467	$	0.43
Effects of dilutive securities:
Exercise of stock options, restricted stock and warrants		—	4,928,847		(0.03	)
Diluted EPS	$	32,000	79,837,314	$	0.40

9

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

A reconciliation of net income and common stock share amounts used in the calculation of basic and diluted EPS for the nine months ended September 30, 2007 and 2006 follows:

	Net Income		Weighted Average Shares Outstanding	Per Share Amount
2007:
Basic EPS	$	22,617	79,329,665	$	0.29
Effects of dilutive securities:
Exercise of stock options, restricted stock and warrants		—	4,142,893		(0.02	)
Diluted EPS	$	22,617	83,472,558	$	0.27
2006:
Basic EPS	$	54,288	67,428,927	$	0.81
Effects of dilutive securities:
Exercise of stock options, restricted stock and warrants		—	3,910,364		(0.05	)
Diluted EPS	$	54,288	71,339,291	$	0.76

Note 5. Comprehensive Income

The components of comprehensive income, net of income tax, are as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Net income	$	7,793	$	32,000	$	22,617	$	54,288
Unrealized gain from hedging activities		506		5,230		862		2,433
Comprehensive income	$	8,299	$	37,230	$	23,479	$	56,721

Note 6. Business Segment Information

Statement of Financial Accounting Standards (“SFAS”) No. 131, “Disclosure about Segments of an Enterprise and Related Information” (“SFAS 131”), establishes standards for reporting information about operating segments in annual financial statements and requires selected information about operating segments in financial reports issued to shareholders. It also establishes standards for related disclosures about products and services, geographic areas and major customers. Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker or decision making group in deciding how to allocate resources and in assessing performance.

In connection with the termination of our marketing arrangement with Aventine on March 31, 2007, we re-evaluated our operating segments based on the application of SFAS 131 and have identified one reportable business segment, the manufacture and marketing of fuel-grade ethanol and the co-products of the ethanol production process as all of our operating segments meet the requirements of aggregation. Our chief operating decision maker reviews financial information presented on a consolidated basis, accompanied by disaggregated information about revenue and certain expenses for purposes of assessing financial performance and making operating decisions. Accordingly, we consider ourselves to be operating in a single industry segment. Previously, we had two reportable segments, ethanol production and other.

Note 7. Material Commitments

We are party to contracts with consultants, independent contractors and other service providers in which we have agreed to indemnify such parties against certain liabilities. Based on historical experience and our assessment of the likelihood that such parties will make claims against us, we believe these indemnification obligations are not material. As of the date of this report, we are not aware of any claims against us.

We believe we are in compliance with applicable environmental laws and regulations and that our environmental controls are adequate to address existing regulatory requirements.

10

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

Note 8. Income Tax

We adopted the provisions of Financial Accounting Standards Board Interpretation 48, Accounting for Uncertainty in Income Taxes (“Interpretation 48”), on January 1, 2007. Previously, we had accounted for tax contingencies in accordance with SFAS No. 5, Accounting for Contingencies. As required by Interpretation 48, which clarifies SFAS No. 109, Accounting for Income Taxes, we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting this standard, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. At the adoption date, we applied Interpretation 48 to all tax positions for which the statute of limitations remained open. We recognized no material adjustment in the liability for unrecognized income tax benefits as a result of implementing Interpretation 48.

There was no amount of unrecognized tax benefit as of January 1, 2007. There have been no material changes in unrecognized tax benefits since January 1, 2007.

We are subject to income taxes in the U.S. federal jurisdiction and various states jurisdictions. Tax regulations within each jurisdiction are subject to the interpretation of the related tax laws and regulations and require significant judgment to apply. With few exceptions, we are no longer subject to the U.S. federal, state or local income tax examinations by tax authorities for the years before 2004.

We are currently under examination by the Internal Revenue Service for tax year 2004 and the short tax year through September 30, 2005. The Internal Revenue Service has proposed certain adjustments to our 2004 and 2005 federal income tax returns. We are contesting those adjustments and have not recognized any effect of the proposed adjustments or any associated interest or penalties based on our assessment of the positions taken in preparing our tax returns. We may not prevail on these positions and, if so, we could recognize incremental income tax expense in future periods. We have not quantified the magnitude of any such potential income tax expense.

We recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in operating expenses for all periods presented. We did not accrue any amounts for the payment of interest and penalties at January 1, 2007. Subsequent changes to accrued interest and penalties are not applicable.

The Company is calculating an effective income tax rate at September 30, 2007 of 19.7%. The income tax provision differs from the amount of income tax determined by applying the U.S. federal income tax rate to pretax income at September 30, 2007, due to the following:

Computed “expected” tax expense	35.0	%
Increase (decrease) in income taxes resulting from:
Stock-based compensation	0.6
State taxes (net of federal tax benefit)	1.4
Tax exempt interest	(19.2	)
Prior year tax return to provision true-up	1.7
Other, net	0.2
	19.7	%

11

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

Note 9. Long-Term Debt

The following table summarizes our long-term debt at the dates indicated:

	September 30, 2007			December 31, 2006
9 7/8% senior secured notes due 2012	$	210,000		$	210,000
9 3/8% senior notes due 2017		450,000			—
Senior credit facility (a)		214,876			—
Capital lease obligation (b)		2,503			—
Tax increment revenue note (c)		5,000			—
Total		882,379			210,000
Less unamortized discount		(3,124	)		(1,095	)
Less current maturities of long-term debt		(235	)		—
Long-term debt	$	879,020		$	208,905

In May 2007, we sold $450,000 aggregate principal amount of Senior Notes due 2017 (the “2017 Notes”) at 99.5% of face value. The 2017 Notes bear interest at a fixed rate of 9.375% per annum and are recorded net of unamortized debt discount of $2,300. The 2017 Notes mature in full on June 1, 2017. They may be redeemed at any time prior to June 1, 2012 by paying a make-whole premium and may be redeemed at any time after June 1, 2012 at specified redemption prices. Interest on the 2017 Notes is paid on a semi-annual basis on June 1 and December 1 of each year beginning on December 1, 2007.

The Senior Secured Notes due 2012 (the “2012 Notes”) bear interest at 9.875% per annum, payable semi-annually in arrears on June 15 and December 15 of each year, and mature on December 15, 2012. They may be redeemed at any time at specified redemption prices. The 2012 Notes are secured on a first priority basis by liens on substantially all of our assets and the assets of the subsidiary guarantors other than accounts receivable, inventory and commodities accounts, and the cash proceeds therefrom.

The 2012 Notes and the 2017 Notes are guaranteed by our existing subsidiaries, other than ASA Holdings and its subsidiaries, and any future restricted subsidiaries that guaranty any of our or any subsidiary guarantor’s other indebtedness. The indentures governing the 2012 Notes and the 2017 Notes contain restrictive covenants which, among other things, limit our ability (subject to exceptions) to (a) make restricted payments (which limits redemption of capital stock, voluntary debt repayments, and investments); (b) incur additional debt; (c) engage in transactions with shareholders and affiliates; (d) pay dividends and other payments restrictions affecting subsidiaries; (e) incur liens on assets; (f) sell assets; and (g) engage in unrelated businesses.

Under the registration rights agreement that was executed in connection with the offering of the 2017 Notes, we agreed to: (a) cause an exchange offer of registered notes to be completed within 365 days after the notes are initially issued and (b) file a shelf registration statement within 365 days after the notes were issued for the resale of the notes if we cannot effect an exchange offer and in some other circumstances. If we have not effected the exchange offer for the 2017 Notes or caused a shelf registration statement with respect to resale of the notes to be declared effective on or prior to such date that is 365 days after the closing date, the annual interest rate will increase by 0.25% per annum and by an additional 0.25% for each subsequent 90-day period, up to a maximum of 1% per annum, until all registration defaults have been cured.

(a) Senior Credit Facility

In connection with the ASA Acquisition, the Senior Credit Facility, as amended, remained in effect and provides for aggregate borrowings of up to $275,000 in two tranches: Tranche A for $175,000 and Tranche B for $100,000. Borrowings under the Senior Credit Facility must be used for the development, engineering, construction and operation of the Company’s Linden, Albion and Bloomingburg plants. Any amounts not utilized for a particular plant may be used at the Company’s option for either of the other two plants. ASA Holdings paid approximately $5,700 in fees at the execution of the agreement on February 6, 2006 and these amounts are included in debt issuance costs in the accompanying condensed consolidated balance sheet, net of amortization.

12

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

At September 30, 2007, the Company had borrowed $136,977 and $77,899 under the Senior Credit Facility in the form of Tranche A and Tranche B construction loans, respectively, in the form of construction loans. The construction loans are available until the earlier of the completion of the plants or March 15, 2008. Upon completion of the plants and full payment of all costs thereto and the satisfaction of certain other conditions, the construction loans may be converted into term loans. Amounts borrowed and repaid under the Senior Credit Facility may not be re-borrowed. The Company pays quarterly commitment fees of 0.5% per annum on the average daily unused amount of the construction loan commitments under the Senior Credit Facility. The Company also pays agent fees of $125 per year.

Tranche A loans bear interest, at the Company’s option, at the administrative agent’s base rate (which is the higher of the federal funds effective rate and the administrative agent’s prime rate) plus 1.5% per annum or a Eurodollar rate based on LIBOR plus 2.5% per annum. Tranche B loans bear interest, at the Company’s option, at the administrative agent base rate plus 3.5% per annum or LIBOR plus 4.5% per annum. The average interest rate for the nine months ended September 30, 2007 was 7.9% and 9.9% for Tranche A loans and Tranche B loans, respectively.

The obligations under the Senior Credit Facility are secured by the assets of ASA Holdings and its subsidiaries and a pledge of all of the equity interests in ASA Holdings.

In the event that the construction loans are not converted into term loans, they mature and are due and payable on March 15, 2008. If converted, the Tranche A term loans would be payable in equal quarterly installments of principal of $2,625 and the Tranche B term loans would be payable in equal quarterly installments of principal of $1,500, plus accrued interest in accordance with the terms of the Senior Credit Facility, and would mature on the earlier of 78 months after the term loan conversion date or June 30, 2014.

After the construction loans have converted to term loans, the Senior Credit Facility requires the Company to prepay the term loans each quarter based on a percentage of the Company’s excess cash flows as defined in the Senior Credit Facility. The interest rates for the term loans are determined in the same manner as rates for construction loans.

The Senior Credit Facility contains various covenants that, among other restrictions, limit ASA Holdings’ ability and the ability of its subsidiaries to make distributions and pay dividends; incur indebtedness and swap and hedge obligations; grant or assume liens; make certain investments; change the nature of their business; issue equity interests not pledged to the lenders; and sell, transfer, assign or convey assets, or engage in certain mergers or acquisitions.

The Senior Credit Facility contains customary events of default and also includes events of default for failure to complete the three ASA Holdings’ plants by March 15, 2008; defaults on other indebtedness by the Company or ASA Holdings and its subsidiaries (including trade debt under certain conditions); and certain changes of control. The Senior Credit Facility also may become in default based on certain actions by Fagen, the design-builder of the Linden, Albion and Bloomingburg facilities, Cargill, and other third parties that provide goods and services to the facilities, including actions that are unrelated to the construction and operation of the facilities. In particular, the material breach by any such third parties of their agreements relating to the facilities, the failure of any such third parties to pay their indebtedness, including trade payables, and the entry of material judgments or the occurrence of an insolvency event with respect to any such third party would constitute an event of default under the Senior Credit Facility.

(b) Capital lease obligation

In connection with the ASA Acquisition, a capital lease obligation for municipal water infrastructure relating to the Linden, Indiana facility remained in effect.

13

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

The schedule of capital lease payments at September 30, 2007 is as follows:

2007	$	30
2008		274
2009		274
2010		274
2011		274
2012		274
Thereafter		4,104
Total		5,504
Less amount representing interest		(3,001	)
Capital lease obligation	$	2,503

(c) Taxable tax increment revenue note

As part of the ASA Acquisition, the Company acquired a taxable tax increment revenue note (“Note”) due to the city of Albion, Nebraska (“City”) with a principal amount of $5,000.

Interest on this note accrues at an initial rate of 8.5% per annum, which shall be adjusted on December 1, 2009, December 1, 2012, and December 1, 2015, to a rate equal to the lower of (1) the Three-Year United States Treasury Constant Maturity Index (as published in The Wall Street Journal on each of such dates or the next published edition thereof containing such rate) plus 425 basis points or (2) 10%. Interest is payable annually on February 1, beginning on February 1, 2008.

The Note is subject to redemption in whole or in part prior to maturity at the option of the Company, on or after February 1, 2009, at a redemption price equal to the percentage of the principal amount being redeemed set forth below, together with accrued interest:

Date	Redemption Price
February 1, 2009 to January 31, 2010	103	%
February 1, 2010 to January 31, 2011	102	%
February 1, 2011 to January 31, 2012	101	%
February 1, 2012 and thereafter	100	%

Principal and interest on the Note are payable out of property taxes expected to be assessed on the Albion facility with minimum principal payments beginning on February 1, 2009 and each year thereafter until maturity on February 1, 2022, in the following amounts:

	Principal Amount
2009	$	199
2010		216
2011		235
2012		276
Thereafter		4,074
Total	$	5,000

Note 10. Guarantors/Non-Guarantors Condensed Consolidating Financial Statements

In accordance with the indentures governing the Company’s senior secured notes and senior unsecured notes, certain wholly owned subsidiaries of the Company have fully and unconditionally guaranteed the notes on a joint and several basis. The following tables present condensed consolidating financial information for VeraSun Energy Corporation (“VEC”), the issuer of the notes, subsidiaries that are guarantors of the notes and subsidiaries that are non-guarantors of the notes. VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Marketing, LLC, VeraSun Hartley, LLC, VeraSun Welcome, LLC, VeraSun Biodiesel, LLC, VeraSun Granite City, LLC, and VeraSun Reynolds, LLC, each 100% wholly-owned subsidiaries of VEC, are combined as guarantors.

14

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING BALANCE SHEET

SEPTEMBER 30, 2007

ASSETS

	Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	323,617		$	—		$	10,298	$	(13,695	)	$	320,220
Receivables		47,438			21,421			9,499		(12,881	)		65,477
Inventories		—			65,802			5,774		(54	)		71,522
Prepaid expenses		1,235			5,891			801		—			7,927
Total current assets		372,290			93,114			26,372		(26,630	)		465,146
Other Assets
Debt issuance costs, net		15,978			—			6,787		—			22,765
Investment in subsidiaries		645,064			—			—		(645,064	)		—
Intercompany notes receivable		442,544			59,120			—		(501,664	)		—
Goodwill		6,129			—			192,456		—			198,585
Other long-term assets		1,197			5,555			224		—			6,976
		1,110,912			64,675			199,467		(1,146,728	)		228,326
Property and equipment, net		13,814			572,840			496,380		—			1,083,034
Total assets	$	1,497,016		$	730,629		$	722,219	$	(1,173,358	)	$	1,776,506
LIABILITIES AND SHAREHOLDERS’ AND MEMBERS’ EQUITY
	Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
Current Liabilities
Outstanding checks in excess of bank balance	$	—		$	13,695		$	—	$	(13,695	)	$	—
Current maturities of long-term debt		—			373,772			235		(373,772	)		235
Current portion of deferred revenues		—			95			—		—			95
Accounts payable		2,055			39,735			13,300		(667	)		54,423
Accrued expenses		23,789			14,482			26,270		(12,214	)		52,327
Derivative financial instruments		—			820			—		—			820
Deferred income taxes		51			1,752			—		—			1,803
Total current liabilities		25,895			444,351			39,805		(400,348	)		109,703
Long-Term Liabilities
Long-term debt, less current maturities		715,996			53,132			237,784		(127,892	)		879,020
Deferred revenue, less current portion		—			1,543			—		—			1,543
Deferred income taxes		5,333			31,115			—		—			36,448
		721,329			85,790			237,784		(127,892	)		917,011
Shareholders’ and Member’s Equity
Common stock		928			—			—		—			928
Additional paid-in capital		636,758			25,263			444,323		(469,586	)		636,758
Retained earnings		112,206			96,287			—		(96,287	)		112,206
Member’s equity		—			79,038			307		(79,345	)		—
Accumulated other comprehensive loss		(100	)		(100	)		—		100			(100	)
		749,792			200,488			444,630		(645,118	)		749,792
	$	1,497,016		$	730,629		$	722,219	$	(1,173,358	)	$	1,776,506

15

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended September 30, 2007

	Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues	$	1,515		$	197,378		$	22,975		$	—		$	221,868
Cost of goods sold		11			177,764			20,699			—			198,474
Gross profit		1,504			19,614			2,276			—			23,394
Startup expenses		—			367			1,308			—			1,675
Selling, general and administrative expenses		7,685			1,901			276			—			9,862
Operating income (loss)		(6,181	)		17,346			692			—			11,857
Other income (expense):
Interest expense		(17,579	)		(5,047	)		(385	)		10,995			(12,016	)
Interest income		15,281			1,237			—			(10,995	)		5,523
Equity in earnings of subsidiaries		10,082			—			—			(10,082	)		—
Other income		2			2			—			—			4
		7,786			(3,808	)		(385	)		(10,082	)		(6,489	)
Income before income taxes		1,605			13,538			307			(10,082	)		5,368
Income tax provision (benefit)		(6,188	)		3,763			—			—			(2,425	)
Net income	$	7,793		$	9,775		$	307		$	(10,082	)	$	7,793
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS For the Nine Months Ended September 30, 2007
	Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues	$	3,927		$	509,032		$	22,975		$	—		$	535,934
Cost of goods sold		31			450,081			20,699			—			470,811
Gross profit		3,896			58,951			2,276			—			65,123
Startup expenses		—			1,949			1,308			—			3,257
Selling, general and administrative expenses		23,074			4,861			276			—			28,211
Operating income (loss)		(19,178	)		52,141			692			—			33,655
Other income (expense):
Interest expense		(35,073	)		(8,825	)		(385	)		24,336			(19,947	)
Interest income		36,331			2,435			—			(24,336	)		14,430
Equity in earnings of subsidiaries		28,874			—			—			(28,874	)		—
Other income		2			34			—			—			36
		30,134			(6,356	)		(385	)		(28,874	)		(5,481	)
Income before income taxes		10,956			45,785			307			(28,874	)		28,174
Income tax provision (benefit)		(11,661	)		17,218			—			—			5,557
Net income	$	22,617		$	28,567		$	307		$	(28,874	)	$	22,617

16

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Nine Months Ended September 30, 2007

	Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(284,422	)	$	16,968		$	21,194		$	319,906		$	73,646
Cash Flows from Investing Activities
Purchases of property and equipment		31,536			(277,733	)		(57,044	)		—			(303,241	)
Payment for other long-term assets		(917	)		(5,355	)		(224	)		—			(6,496	)
ASA Acquisition		(250,000	)		—			7,225			—			(242,775	)
Proceeds from sale of equipment		5			1			—			—			6
Net cash used in investing activities		(219,376	)		(283,087	)		(50,043	)		—			(552,506	)
Cash Flows from Financing Activities
Outstanding checks in excess of bank balance		—			7,596			—			(7,596	)		—
Proceeds from long-term debt		447,750			—			23,617			—			471,367
Principal payments on long-term debt		45,746			258,521			15,639			(319,906	)		—
Proceeds from the issuance of common stock		12,784			—			—			—			12,784
Excess tax benefits from share-based payment arrangements		8,424			—			—			—			8,424
Costs of raising capital		(5	)		—			—			—			(5	)
Debt issuance costs paid		(11,430	)		—			(109	)		—			(11,539	)
Net cash provided by (used in) financing activities		503,269			266,117			39,147			(327,502	)		481,031
Net increase (decrease) in cash and cash equivalents		(529	)		(2	)		10,298			(7,596	)		2,171
Cash and cash equivalents, beginning of period		324,146			2			—			(6,099	)		318,049
Cash and cash equivalents, end of period	$	323,617		$	—		$	10,298		$	(13,695	)	$	320,220

17

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2006

ASSETS

	Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	324,146		$	2		$	—	$	(6,099	)	$	318,049
Receivables		4,326			59,309			—		(1,086	)		62,549
Inventories		—			39,103			—		(54	)		39,049
Prepaid expenses		450			3,737			—		—			4,187
Derivative financial instruments		—			12,382			—		—			12,382
Total current assets		328,922			114,533			—		(7,239	)		436,216
Other Assets
Restricted cash held in escrow		44,267			—			—		—			44,267
Debt issuance costs, net		5,685			—			—		—			5,685
Investment in subsidiaries		171,005			—			—		(171,005	)		—
Intercompany notes receivable		168,385			13,374			—		(181,759	)		—
Deposits		280			200								480
Goodwill		6,129			—			—		—			6,129
Deferred income taxes		5,716			365			—		(6,081	)		—
		401,467			13,939			—		(358,845	)		56,561
Property and equipment, net		642			301,078			—		—			301,720
Total assets	$	731,031		$	429,550		$	—	$	(366,084	)	$	794,497
LIABILITIES AND SHAREHOLDERS’ AND MEMBERS’ EQUITY
	Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
Current Liabilities
Outstanding checks in excess of bank balance	$	—		$	6,099		$	—	$	(6,099	)	$	—
Current maturities of long-term debt		—			110,519			—		(110,519	)		—
Current portion of deferred revenue		—			96			—		—			96
Accounts payable		848			35,548			—		(5	)		36,391
Accrued expenses		1,389			2,654			—		(1,082	)		2,961
Derivative financial instruments		—			11,331			—		—			11,331
Deferred income taxes		83			1,287								1,370
Total current liabilities		2,320			167,534			—		(117,705	)		52,149
Long-Term Liabilities
Long-term debt, less current maturities		222,280			57,864			—		(71,239	)		208,905
Deferred revenue, less current portion		—			1,613			—		—			1,613
Deferred income taxes		—			31,480			—		(6,081	)		25,399
		222,280			90,957			—		(77,320	)		235,917
Shareholders’ and Member’s Equity
Common stock		755			—			—		—			755
Additional paid-in capital		417,049			25,263			—		(25,263	)		417,049
Retained earnings		89,589			84,013			—		(84,013	)		89,589
Member’s equity		—			62,745			—		(62,745	)		—
Accumulated other comprehensive loss		(962	)		(962	)		—		962			(962	)
		506,431			171,059			—		(171,059	)		506,431
	$	731,031		$	429,550		$	—	$	(366,084	)	$	794,497

18

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended September 30, 2006

	Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
Revenues	$	—		$	148,249		$	—	$	—		$	148,249
Cost of goods sold		13			85,583			—		—			85,596
Gross profit (loss)		(13	)		62,666			—		—			62,653
Startup expenses		—			235			—		—			235
Selling, general and administrative expenses		2,522			4,667			—		—			7,189
Operating income (loss)		(2,535	)		57,764			—		—			55,229
Other income (expense):
Interest expense		(5,939	)		(1,679	)		—		3,172			(4,446	)
Interest income		7,681			472			—		(3,172	)		4,981
Equity in earnings of subsidiaries		35,255			—			—		(35,255	)		—
Other income		188			2,482			—		—			2,670
		37,185			1,275			—		(35,255	)		3,205
Income before income taxes		34,650			59,039			—		(35,255	)		58,434
Income tax provision		2,650			20,726			—		—			23,376
Net income	$	32,000		$	38,313		$	—	$	(35,255	)	$	35,058
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS For the Nine Months Ended September 30, 2006
	Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
Revenues	$	—		$	412,657		$	—	$	—		$	412,657
Cost of goods sold		998			259,782			—		—			260,780
Gross profit (loss)		(998	)		152,875			—		—			151,877
Startup expenses		—			541			—		—			541
Selling, general and administrative expenses		21,477			11,588			—		—			33,065
Operating income (loss)		(22,475	)		140,746			—		—			118,271
Other income (expense):
Interest expense		(37,669	)		(9,074	)		—		12,235			(34,508	)
Interest income		19,521			1,665			—		(12,235	)		8,951
Equity in earnings of subsidiaries		85,487			—			—		(85,487	)		—
Other income		188			2,503			—		—			2,691
		67,527			(4,906	)		—		(85,487	)		(22,866	)
Income before income taxes		45,052			135,840			—		(85,487	)		95,405
Income tax provision (benefit)		(9,236	)		50,353			—		—			41,117
Net income	$	54,288		$	85,487		$	—	$	(85,487	)	$	54,288

19

VERASUN ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Nine Months Ended September 30, 2006

	Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
Net cash provided by operating activities	$	9,310		$	108,062		$	—	$	—		$	117,372
Cash Flows from Investing Activities
Investment in restricted cash		(1,631	)		—			—		—			(1,631	)
Purchases of property and equipment with restricted cash held in escrow		43,945			(43,945	)		—		—			—
Proceeds from sale of equipment		—			838			—		—			838
Principal payments received on notes receivable		49,981			—			—		(49,981	)		—
Purchases of property and equipment		—			(15,626	)		—		—			(15,626	)
Net cash provided by (used in) investing activities		92,295			(58,733	)		—		(49,981	)		(16,419	)
Cash Flows from Financing Activities
Outstanding checks in excess of bank balance		—			652			—		(652	)		—
Principal payments on long-term debt		—			(49,981	)		—		49,981			—
Net proceeds from issuance of common stock		233,135			—			—		—			233,135
Excess tax benefits from share-based payment arrangements		17			—			—		—			17
Debt issuance costs paid		(1,173	)		—			—		—			(1,173	)
Net cash provided by (used in) financing activities		231,979			(49,329	)		—		49,329			231,979
Net increase in cash and cash equivalents		333,584			—			—		(652	)		332,932
Cash and cash equivalents, beginning of period		32,905			—			—		(3,191	)		29,714
Cash and cash equivalents, end of period	$	366,489		$	—		$	—	$	(3,843	)	$	362,646

Note 11. Subsequent Event

On October 1, 2007, the Company issued a press release announcing that the Company is suspending construction of its 110 million gallon per year ethanol biorefinery in Reynolds, Indiana, due to market conditions. As of September 30, 2007, the Company had spent approximately $54,000 on this facility. No impairment has been recorded as the Company expects to resume construction in 2008, depending upon the return of more favorable market conditions. The estimated cost to complete the facility is approximately $130,000.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD LOOKING STATEMENTS

The following information should be read in conjunction with the condensed consolidated financial statements and notes thereto included in Part I, Item 1 of this quarterly report and the audited consolidated financial statements and notes thereto contained in the Company’s annual report on Form 10-K filed with the Securities and Exchange Commission on March 29, 2007. VeraSun Energy Corporation and its subsidiaries are collectively referred to as “Company,” “we,” “us” and “our”.

This management’s discussion and analysis of financial condition and results of operations (“MD&A”) contains forward-looking statements which are subject to risks and uncertainties. Many factors could cause actual results to differ materially from those projected in forward-looking statements, including the risks described in Part II, Item 1A of this quarterly report. These forward-looking statements include any statements related to our expectations regarding future performance or conditions, including construction of new facilities, the production volumes of those facilities, anticipated costs to construct new facilities, completion of pending or future acquisitions, development of alternative technologies, future marketing arrangements and the adequacy of anticipated sources of cash to fund our future capital requirements. Our actual results may differ materially from those discussed in the forward-looking statements. Words such as “believes,” “anticipates,” “expects,” “intends,” “plans” and similar expressions are intended to identify forward-looking statements, but are not the exclusive means of identifying such statements. We do not undertake any duty to update forward-looking statements after the date they are made or to conform them to actual results or to changes in circumstances or expectations.

Business Overview

VeraSun is one of the largest ethanol producers in the United States based on production capacity, according to the Renewable Fuels Association (“RFA”). We focus primarily on the production and sale of ethanol and its co-products. This focus has enabled us to significantly grow our ethanol production capacity and to work with automakers, fuel distributors, trade associations and consumers to increase the demand for ethanol. As an industry leader, we play an active role in developments within the renewable fuels industry.

Ethanol is a type of alcohol produced in the U.S. principally from corn. Ethanol is primarily used as a blend component in the U.S. gasoline fuel market, which approximated 142 billion gallons in 2006 according to the Energy Information Administration (“EIA”). Refiners and marketers have historically blended ethanol with gasoline to increase octane and reduce tailpipe emissions. The ethanol industry has grown significantly over the last few years, expanding production capacity at a compounded annual growth rate of approximately 22% from 2000 to 2006. We believe the ethanol market will continue to grow as a result of ethanol’s cleaner burning characteristics, a shortage of domestic petroleum refining capacity, geopolitical concerns, and federally mandated renewable fuel usage. We also believe that E85, a fuel blend composed of 85% ethanol, may become increasingly important as an alternative to unleaded gasoline.

We own and operate five of the largest ethanol production facilities in the U.S., with a combined ethanol production capacity of 560 million gallons per year, or “MMGY.” As of November 1, 2007, our ethanol production capacity represented approximately 8.9% of the total ethanol production capacity in the U.S., according to the RFA.

Our facilities are designed to operate on a continuous basis and use current dry-milling technology, a production process that results in increased ethanol yield and reduced capital costs compared to wet-milling facilities. In addition to producing ethanol, we produce and sell wet and dry distillers grains as ethanol co-products, which serve to partially offset our corn costs. In 2006, we produced approximately 226.3 million gallons of fuel ethanol and 492,000 tons of distillers grains.

We commenced operations at our facility in Aurora, South Dakota in December 2003, at our facility in Fort Dodge, Iowa in October 2005, at our facility in Charles City, Iowa in April 2007, at our facility in Linden, Indiana in August 2007, and at our facility in Albion, Nebraska in October 2007. Construction of our facilities in Hartley, Iowa; Welcome, Minnesota; and Bloomingburg, Ohio has commenced and we expect each of those facilities to begin production during the first six months of 2008. Upon completion of these facilities, we will have production capacity of 890 MMGY. We also broke ground for a facility in Reynolds, Indiana in April 2007. However, in October 2007 we suspended construction there because of market conditions. We expect to resume construction at Reynolds in 2008, depending on the return of more favorable market conditions, and bring our production capacity to one billion gallons per year by the end of 2009.

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Executive Summary

Financial highlights for the three months ended September 30, 2007 are as follows:

• Revenues of $221.9 million, a 49.7% percent increase over the three months ended September 30, 2006.

• Net income of $7.8 million, compared to net income of $32 million for the three months ended September 2006.

• Diluted earnings per share (EPS) of $0.09, compared to EPS of $0.40 for the three months ended September 30, 2006.

• EBITDA of $22.4 million, or 10.1% of revenues ($0.24 per gallon sold)

• Ethanol sales of 95.1 million gallons, a 71.8% increase over the three months ended September 30, 2006.

• Ethanol production of 99.4 million gallons, a 77.4% increase over the three months ended September 30, 2006.

Components of Revenues and Expenses

Total revenues. Our primary source of revenue is the sale of ethanol produced at our Aurora, Fort Dodge, Charles City and Linden facilities. Our principal sources of revenue are:

• the sale of ethanol;

• the sale of distillers grains, which are co-products of the ethanol production process; and

• the sale of ethanol blended VE85™ fuel.

The selling prices for our ethanol are largely determined by the market demand for ethanol which, in turn, is influenced by the industry factors described elsewhere in this report.

Cost of goods sold and gross profit. Our gross profit is derived from our total revenues less our cost of goods sold. Our cost of goods sold is mainly affected by the cost of corn, natural gas and transportation. Corn is our most significant raw material cost. The price of corn is influenced by weather conditions and other factors affecting crop yields, farmer planting decisions and general economic, market and regulatory factors. These factors include government policies and subsidies with respect to agriculture and international trade, and global and local demand and supply. The spot price of corn tends to rise during the spring planting season and tends to decrease during the fall harvest. We purchase natural gas to power steam generation in our ethanol production process and to dry our distillers grains. Natural gas represents our second largest cost. Cost of goods sold also includes net gain or loss from derivatives relating to corn and natural gas. Transportation expense represents the third major component of our cost of goods sold. Transportation expense includes freight and shipping of our ethanol and co-products, as well as costs incurred in storing ethanol at destination terminals.

Startup expenses. Costs associated with the operation of a facility prior to the production and sale of ethanol are expensed as incurred. For the three months ended September 30, 2007, we incurred startup expenses relating to the Albion, Nebraska; Hartley, Iowa; Bloomingburg, Ohio; Welcome, Minnesota; and Reynolds, Indiana facilities. For the three months ended September 30, 2006, the startup expenses pertained to the Charles City, Iowa facility. For the nine months ended September 30, 2007, we incurred startup expenses relating to the Charles City, Iowa; Albion, Nebraska; Hartley, Iowa; Bloomingburg, Ohio; Welcome, Minnesota; and Reynolds, Indiana facilities. For the nine months ended September 30, 2006, the startup expenses pertained to the Charles City, Iowa facility.

Selling, general and administrative expenses. Selling, general and administrative expenses consist of salaries and benefits paid to our administrative employees including stock-based compensation, taxes, expenses relating to third-party services, insurance, travel, marketing and other expenses. Other expenses include education and training, marketing, travel, corporate donations and other miscellaneous overhead costs.

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Other income (expense). Other income (expense) includes the interest on our long-term debt and notes payable, the change in fair value of a put warrant in the 2006 periods, and the amortization of the related fees to execute required financing agreements. We expect interest expense, net of interest capitalized as part of new plant construction, to increase significantly as a result of our issuance of additional debt in the three months ended June 30, 2007 and debt assumed in the three months ended September 30, 2007.

Results of Operations

The following table sets forth, for the periods presented, revenues, expenses and net income, as well as the percentage relationship to total revenues of specified items in our condensed consolidated statements of operations:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2007					2006				2007					2006
	(unaudited)
	(dollars in thousands)
Total revenues	$	221,868		100.0	%	$	148,249	100.0	%	$	535,934		100.0	%	$	412,657		100.0	%
Cost of goods sold		198,474		89.5			88,654	59.6			470,811		87.8			260,780		63.1
Gross profit		23,394		10.5			59,595	40.4			65,123		12.2			151,877		36.9
Startup expenses		1,675		0.8			235	0.2			3,257		0.6			541		0.1
Selling, general and administrative expenses		9,862		4.4			7,189	4.8			28,211		5.3			33,065		8.0
Operating income		11,857		5.3			52,171	35.4			33,655		6.3			118,271		28.8
Other income (expense), net		(6,489	)	(2.9	)		3,205	2.1			(5,481	)	(1.0	)		(22,866	)	(5.6	)
Income before income taxes		5,368		2.4			55,376	37.5			28,174		5.3			95,405		23.2
Income tax provision (benefit)		(2,425	)	(1.1	)		23,376	15.8			5,557		1.0			41,117		10.0
Net income	$	7,793		3.5	%	$	32,000	21.7	%	$	22,617		4.3	%	$	54,288		13.2	%

The following table sets forth other key data for the periods presented (in thousands, except per unit data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Operating data:
Ethanol gallons sold (1)		95,133		56,280		218,689		167,865
Average gross price of ethanol sold (dollars per gallon)	$	1.96	$	2.36	$	2.07	$	2.18
Average corn cost per bushel		3.32		2.05		3.58		2.03
Average natural gas cost per MMBTU		6.17		7.70		6.59		8.35
Average dry distillers grains gross price per ton		94		81		92		83
Other financial data:
EBITDA (2)	$	22,424	$	62,241	$	59,241	$	137,078
Net cash flows provided by operating activities		49,524		61,975		73,646		117,372

(1) Excludes ethanol sold in VE85™ sales.

(2) EBITDA is defined as earnings before interest expense, income tax provision (benefit), depreciation and amortization. Amortization of debt issuance costs and debt discount are included in interest expense.

Non-GAAP Financial Measures

We believe that earnings before interest expense, income tax provision (benefit), depreciation and amortization, or EBITDA, is useful to investors and management in evaluating our operating performance in relation to other companies in our industry because the calculation of EBITDA generally eliminates the effects of financings and income taxes, which items may vary for different companies

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for reasons unrelated to overall operating performance. EBITDA is a non-GAAP financial measure and has limitations as an analytical tool, and should not be considered in isolation or as a substitute for net income or any other measure of performance under GAAP, or to cash flows from operating, investing or financing activities as a measure of liquidity. Some of the limitations of EBITDA are:

• EBITDA does not reflect our cash used for capital expenditures;

• Although depreciation and amortization are non-cash charges, the assets being depreciated or amortized often will have to be replaced and EBITDA does not reflect the cash requirements for replacements;

• EBITDA does not reflect changes in, or cash requirements for, our working capital requirements;

• EBITDA does not reflect the cash necessary to make payments of interest or principal on our indebtedness; and

• EBITDA includes non-recurring payments to us which are reflected in other income.

We compensate for these limitations by relying on our GAAP results, as well as on our EBITDA.

The following table reconciles our EBITDA to net income for the periods presented (dollars in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2007			2006		2007		2006
Net income	$	7,793		$	32,000	$	22,617	$	54,288
Depreciation and amortization		5,040			2,419		11,120		7,165
Interest expense		12,016			4,446		19,947		34,508
Income tax provision (benefit)		(2,425	)		23,376		5,557		41,117
EBITDA	$	22,424		$	62,241	$	59,241	$	137,078

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

Total revenues. Total revenues, which includes revenue from the sale of ethanol, distillers grains and VE85™, increased by $73.6 million, or 49.7%, to $221.9 million for the three months ended September 30, 2007 from $148.2 million for the three months ended September 30, 2006. The increase in total revenues was primarily the result of an 71.8% increase in ethanol volume sold, partially offset by a decrease in average ethanol prices of $0.40 per gallon, or 17.0%, compared to the three months ended September 30, 2006. Ethanol production increased by 43.4 million gallons, or 77.4%, as a result of the added capacity from bringing the Charles City, Iowa facility on-line in April 2007 and the Linden, Indiana facility on-line in August 2007.

Net sales from ethanol increased $58.0 million, or 44.4%, to $188.5 million for the three months ended September 30, 2007 from $130.5 million for the three months ended September 30, 2006. The impact of increased volume, primarily from the additional Charles City and Linden capacity, was $93.7 million, partially offset by a $35.7 million reduction due to lower prices. The average price of ethanol sold was $1.96 per gallon for the three months ended September 30, 2007 compared to $2.36 per gallon for the three months ended September 30, 2006.

The net loss from derivatives included in net sales was $0.3 million for the three months ended September 30, 2007 compared to a net gain of $0.9 million for the three months ended September 30, 2006.

Net sales from co-products increased $14.3 million, or 101.8%, to $28.4 million for the three months ended September 30, 2007 from $14.1 million for the three months ended September 30, 2006. The impact of increased volume from the additional Charles City and Linden capacity was $10.9 million and the impact of higher prices was $3.5 million.

Net sales of VE85^TM, our branded E85 product, increased $1.1 million, or 37.5%, to $3.9 million for the three months ended September 30, 2007 from $2.8 million for the three months ended September 30, 2006, primarily due to an increase in the number of retail outlets selling our product.

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Cost of goods sold and gross profit. Gross profit decreased $36.2 million to $23.4 million for the three months ended September 30, 2007 from $59.6 million for the three months ended September 30, 2006. The decrease in gross profit was primarily due to higher corn costs, partially offset by an increase in ethanol volume produced in the 2007 period compared to the 2006 period. Also included in cost of sales for the period ended September 30, 2007 were a $0.6 million lower of cost or market write down of ethanol inventory and a $0.6 million impairment relating to a cancelled biodiesel project. Results for the full year 2007 are also expected to be adversely affected by these relatively higher corn costs.

Corn costs increased $74.5 million to $115.2 million for the three months ended September 30, 2007 from $40.7 million for the three months ended September 30, 2006. Corn costs represented 58.0% of our cost of goods sold before taking into account our co-product sales and 43.7% of our cost of goods sold after taking into account co-product sales for the three months ended September 30, 2007, compared to 46.3% of our cost of goods sold before taking into account our co-product sales and 30.3% of our cost of goods sold after taking into account co-product sales for the three months ended September 30, 2006.

The increase in total corn costs for the three months ended September 30, 2007 was primarily driven by an increase in cash corn prices compared to the three months ended September 30, 2006. In addition, our corn costs in the three months ended September 30, 2007 included a mark-to-market loss of $0.7 million for derivatives relating to future deliveries of corn. We had recorded a mark-to-market gain of $1.4 million in the three months ended September 30, 2006, resulting in a $2.1 million increase in corn costs between the periods as a result of these mark-to-market adjustments.

The net gain from derivatives included in cost of goods sold was $13.7 million for the three months ended September 30, 2007 compared to a net loss of $0.1 million for the three months ended September 30, 2006. The increase was primarily due to the mark-to-market adjustment described above. We mark all exchange traded corn futures contracts to market through costs of goods sold.

Natural gas costs increased $5.0 million to $18.5 million for the three months ended September 30, 2007 from $13.5 million for the three months ended September 30, 2006, and accounted for 9.3% of our cost of goods sold for the three months ended September 30, 2007 compared to 15.4% of our cost of goods sold for the three months ended September 30, 2006. The increase in natural gas costs for the three months ended September 30, 2007 was attributable to an increase in our production compared to the three months ended September 30, 2006, partially offset by a decrease in natural gas prices per million British Thermal Units, or MMBTU, in the three months ended September 30, 2007.

Transportation expense increased $9.8 million to $24.6 million for the three months ended September 30, 2007 from $14.8 million for the three months ended September 30, 2006, primarily due to additional volume of ethanol and co-products shipped, and increased rail rates in the three months ended September 30, 2007. Transportation expense accounted for 12.4% of our cost of goods sold for the three months ended September 30, 2007 compared to 16.8% of our cost of goods sold for the three months ended September 30, 2006.

Labor and manufacturing overhead costs increased $9.6 million to $17.8 million for the three months ended September 30, 2007 from $8.1 million for the three months ended September 30, 2006. The increase was primarily due to additional production at our Charles City, Iowa and Linden, Indiana facilities. Also included in overhead was a $0.6 million impairment of assets related to a canceled biodiesel project.

Startup expenses. Startup expenses increased $1.5 million to $1.7 million for the three months ended September 30, 2007 from $0.2 million for the three months ended September 30, 2006. The increase was due to the increase in the number of plants in startup mode. In the three months ended September 30, 2006, the Charles City, Iowa plant was starting up, while in 2007, the Hartley, Iowa, Welcome, Minnesota, Reynolds, Indiana, Albion, Nebraska, and the Bloomingburg, Ohio facilities were all in startup mode.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $2.7 million to $9.9 million for the three months ended September 30, 2007 from $7.2 million for the three months ended September 30, 2006. The increase was primarily the result of an increase in stock compensation expense and increased management and administrative costs in the 2007 period to support our growth and public company status.

Other income (expense). Interest expense increased $7.6 million to $12.0 million for the three months ended September 30, 2007, compared to $4.4 million for the three months ended September 30, 2006. This was primarily due to the issuance of additional debt in the second quarter of 2007 and interest expense under the Senior Credit Facility from the date of the ASA Acquisition.

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Interest income increased $0.5 million to $5.5 million for the three months ended September 30, 2007, compared to $5.0 million for the three months ended September 30, 2006. The increase was primarily attributable to an increase in the funds available to be invested in interest bearing securities.

Income taxes. The income tax benefit was $2.4 million for the three months ended September 30, 2007, versus an income tax provision of $23.4 million for the three months ended September 30, 2006. The effective tax rate for the three months ended September 30, 2007 was (45.2)%, compared to 42.2% for the three months ended September 30, 2006. The effective tax rate was higher in the 2006 period due to nondeductible expense associated with the increase in the estimated fair value of the put warrant and the accelerated vesting of incentive stock option and restricted stock awards in connection with our initial public offering, or IPO. The 2007 effective tax rate declined from our previous estimate of 35% to 19.7% due to a reduction in the full year estimated “income before income taxes” caused by current market conditions and an increase in the estimated tax exempt interest income, both in dollars and as a percent of “income before income taxes”. The tax benefit is the result of a year to date cumulative adjustment resulting in a change in the expected annual tax rate during the quarter.

The Internal Revenue Service has proposed certain adjustments to our 2004 and 2005 federal income tax returns. We are contesting those adjustments and have not recognized any effect of the proposed adjustments or any associated interest or penalties based on our assessment of the positions taken in preparing our tax returns. We may not prevail on these positions and, if so, we could recognize incremental income tax expense in future periods. We have not quantified the magnitude of any such potential income tax expense.

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

Total revenues. Total revenues, which includes revenue from the sale of ethanol, distillers grains and VE85™, increased by $123.3 million, or 29.9%, to $535.9 million for the nine months ended September 30, 2007 from $412.7 million for the nine months ended September 30, 2006. The increase in total revenues was primarily the result of a 31.4% increase in ethanol volume sold, partially offset by a decrease in average ethanol prices of $0.11 per gallon, or 5.2%, compared to the nine months ended September 30, 2006. Ethanol production increased by 70.2 million gallons, or 42.1%, as a result of the added capacity from bringing the Charles City, Iowa facility on-line in April 2007 and the Linden, Indiana facility on-line in August 2007.

Net sales from ethanol increased $94.0 million, or 26.0%, to $456.2 million for the nine months ended September 30, 2007 from $362.2 million for the nine months ended September 30, 2006. The impact of increased volume, primarily from the additional Charles City and Linden capacity was $118.9 million, partially offset by the impact from lower prices of $24.8 million. The average price of ethanol sold was $2.07 per gallon for the nine months ended September 30, 2007 compared to $2.18 per gallon for the nine months ended September 30, 2006.

The net loss from derivatives included in net sales was $1.2 million for the nine months ended September 30, 2007 compared to a net loss of $0.5 million for the nine months ended September 30, 2006.

Net sales from co-products increased $25.7 million, or 61.8%, to $67.3 million for the nine months ended September 30, 2007 from $41.6 million for the nine months ended September 30, 2006. Co-product sales increased $18.9 million primarily as a result of the additional production volume from the Charles City and Linden facilities and $6.8 million due to an increase in the average price per ton in the 2007 period.

Net sales of VE85^TM, our branded E85 product, increased $4.0 million to $9.8 million for the nine months ended September 30, 2007 from $5.8 million for the nine months ended September 30, 2006, primarily due to an increase in the number of retail outlets selling our product.

Cost of goods sold and gross profit. Gross profit decreased $86.8 million to $65.1 million for the nine months ended September 30, 2007 from $151.9 million for the nine months ended September 30, 2006. The decrease in gross profit was primarily due to higher corn costs and lower ethanol prices, partially offset by an increase in ethanol volume sold in the 2007 period compared to the 2006 period. Also included in cost of goods sold for the period ended September 30, 2007 were a $0.6 million lower of cost or market write down of ethanol inventory and a $0.6 million impairment relating to a cancelled biodiesel project. Results for the full year 2007 are also expected to be adversely affected by these relatively higher corn costs.

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Corn costs increased $161.6 million to $280.9 million for the nine months ended September 30, 2007 from $119.3 million for the nine months ended September 30, 2006. Corn costs represented 59.7% of our cost of goods sold before taking into account our co-product sales and 45.4% of our cost of goods sold after taking into account co-product sales for the nine months ended September 30, 2007, compared to 46.0% of our cost of goods sold before taking into account our co-product sales and 30.0% of our cost of goods sold after taking into account co-product sales for the nine months ended September 30, 2006.

The increase in total corn costs in the 2007 period was primarily driven by an increase in cash corn prices compared to the 2006 period. In addition, our corn costs for the nine months ended September 30, 2007 included a mark-to-market loss of $0.6 million for derivatives relating to future deliveries of corn. We had a mark-to-market gain of $1.8 million in the 2006 period, resulting in a $2.4 million increase in corn costs between the periods as a result of these mark-to-market adjustments.

The net gain from derivatives included in cost of goods sold was $5.6 million for the nine months ended September 30, 2007 compared to a net loss of $5.3 million for the nine months ended September 30, 2006. The increase was primarily due to the mark-to-market adjustment described above. We mark all exchange traded corn futures contracts to market through costs of goods sold.

Natural gas costs increased $4.5 million to $47.6 million for the nine months ended September 30, 2007 from $43.1 million for the nine months ended September 30, 2006, and accounted for 10.1% of our cost of goods sold for the nine months ended September 30, 2007 compared to 16.6% of our cost of goods sold for the nine months ended September 30, 2006. The increase in natural gas costs was attributable to an increase in our production compared to the 2006 period, partially offset by a decrease in natural gas prices in the 2007 period.

Transportation expense increased $14.0 million to $54.8 million for the nine months ended September 30, 2007 from $40.8 million for the nine months ended September 30, 2006, primarily due to additional volume of ethanol and co-products shipped, and increased rail rates for the 2007 period. Transportation expense accounted for 11.6% of our cost of goods sold for the nine months ended September 30, 2007 compared to 15.7% of our cost of goods sold for the nine months ended September 30, 2006.

Labor and manufacturing overhead costs increased $13.1 million to $36.5 million for the nine months ended September 30, 2007 from $23.5 million for the nine months ended September 30, 2006. The increase was primarily due to the Charles City and Linden facilities being operational in the 2007 period as well additional staffing needed to achieve higher production rates from our operating facilities. Also included in overhead was a $0.6 million impairment of assets relating to a canceled biodiesel project.

Startup expenses. Startup expenses increased $2.7 million to $3.2 million for the nine months ended September 30, 2007 from $0.5 million for the nine months ended September 30, 2006. The increase was due to the increase in the number of plants in startup mode. In the 2006 period, the Charles City, Iowa plant was starting up, while in the 2007 period, the Charles City, Iowa, Hartley, Iowa; Welcome, Minnesota; Reynolds, Indiana; Albion, Nebraska; and the Bloomingburg, Ohio, facilities were all in startup mode.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $4.9 million to $28.2 million for the nine months ended September 30, 2007 from $33.1 million for the nine months ended September 30, 2006. The decrease was primarily the result of a charge to stock compensation expense in the 2006 period of $16.3 million in connection with our IPO, partially offset by increased management and administrative costs in the 2007 period to support our growth and public company status.

Other income (expense). Interest expense decreased $14.6 million to $19.9 million for the nine months ended September 30, 2007 compared to $34.5 million for the nine months ended September 30, 2006. Interest expense in the 2006 period included a charge of $19.7 million relating to a warrant that was fully exercised in connection with our IPO.

Interest income increased $5.4 million to $14.4 million for the nine months ended September 30, 2007 compared to $9.0 million for the nine months ended September 30, 2006. The increase was primarily attributable to an increase in the funds available to be invested in interest bearing securities.

Income taxes. The income tax provision was $5.6 million and $41.1 million for the nine months ended September 30, 2007 and 2006, respectively. The effective tax rate for the nine months ended September 30, 2007 was 19.7% compared to 43.1% for the nine months ended September 30, 2006. The effective tax rate was higher in the 2006 period due to nondeductible expense associated with the increase in the estimated fair value of the put warrant and the accelerated vesting of incentive stock option and restricted stock awards in connection with our IPO. The 2007 effective tax rate declined from our previous estimate of 35% to 19.7% due to a reduction in the full year estimated “income before income taxes” caused by current market conditions and an increase in the estimated tax exempt interest income, both in dollars and as a percent of “income before income taxes”.

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The Internal Revenue Service has proposed certain adjustments to our 2004 and 2005 federal income tax returns. We are contesting those adjustments and have not recognized any effect of the proposed adjustments or any associated interest or penalties based on our assessment of the positions taken in preparing our tax returns. We may not prevail on these positions and, if so, we could recognize incremental income tax expense in future periods. We have not quantified the magnitude of any such potential income tax expense.

Liquidity and Capital Resources

Our principal sources of liquidity consist of the issuance of common stock, cash and cash equivalents on hand, cash provided by operations and available borrowings under our credit agreements. We have also issued long-term debt as a source of funds, including $210.0 million aggregate principal amount of senior secured notes in December 2005 and $450.0 million aggregate principal amount of senior notes in May 2007. In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new facilities, capital expenditures, acquisitions and debt service requirements.

The following table summarizes our sources and uses of cash and cash equivalents from our unaudited condensed consolidated statements of cash flows for the periods presented (in thousands):

	Nine Months Ended September 30,
	2007			2006
Net cash provided by operating activities	$	73,646		$	117,372
Net cash used in investing activities		(552,506	)		(16,419	)
Net cash provided by financing activities		481,031			231,979
Net increase in cash and cash equivalents	$	2,171		$	332,932

We believe that net cash provided by operating activities is useful to investors and management as a measure of the ability of our business to generate cash which can be used to meet business needs and obligations or to re-invest for future growth.

Cash provided by operating activities was $73.6 million for the nine months ended September 30, 2007 compared to $117.4 million provided by operating activities for the nine months ended September 30, 2006. Our inventory increased $29.2 million during the nine months ended September 30, 2007, primarily because of the termination of our marketing relationship with Aventine. Under the Aventine relationship, ethanol was transferred to Aventine at our facilities so that our inventory of ethanol was limited to work in process and ethanol that had not been loaded into railcars at the facilities. Our inventory balances now include ethanol in transit to customers. The inventory impact of terminating the Aventine relationship is partially offset by our marketing relationship with Cargill at our Linden, Albion and Bloomingburg facilities. Like the Aventine relationship, the Cargill relationship reduces our inventory requirements at those facilities as compared to our other facilities. As we add additional facilities, we expect that our total working capital requirements will increase. At September 30, 2007, we had total unrestricted cash and cash equivalents of $320.2 million compared to $362.7 million at September 30, 2006.

Cash used in investing activities was $552.5 million for the nine months ended September 30, 2007 compared to cash used of $16.4 million for the nine months ended September 30, 2006. The increase primarily resulted from construction expenditures, the cash portion of the purchase price of the ASA Acquisition, and the acquisitions of other fixed assets in the 2007 period. In addition, $44.3 million was spent from escrowed cash for the construction of our Charles City facility.

Cash provided by financing activities for the nine months ended September 30, 2007 was $481.0 million compared to $232.0 million provided by financing activities for the nine months ended September 30, 2006. The 2006 period included debt issuance costs and net proceeds from our IPO. The 2007 period included proceeds from long-term debt and debt issuance costs.

As of September 30, 2007, we had total debt of $879.3 million, net of $3.1 million of unaccreted debt discount. In addition, we had $6.5 million of letters of credit issued but not drawn under our $30.0 million credit agreement, leaving $23.5 million of borrowing capacity under that agreement at September 30, 2007. The amount undrawn on the Senior Credit Facility was $60.1 million as of September 30, 2007.

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Our financial position and liquidity are, and will be, influenced by a variety of factors, including:

• our ability to generate cash flows from operations;

• the level of our outstanding indebtedness and the interest we are obligated to pay on this indebtedness; and

• our capital expenditure requirements, which consist primarily of plant construction and the purchase of equipment.

We intend to fund our principal liquidity and capital resource requirements through cash and cash equivalents, cash provided by operations and borrowings under our credit agreements.

In addition to the construction of our planned Hartley, Welcome, Bloomingburg and Reynolds facilities and oil extraction units at our Aurora, Charles City and Fort Dodge facilities, we also may consider additional opportunities for growing our production capacity, including the development of additional sites and the expansion of one or more of our existing facilities. Acquisitions or further expansion of our operations could cause our indebtedness, and our ratio of debt to equity, to increase. The indentures governing our 2012 Notes and 2017 Notes and the terms of our credit agreements limit our ability to incur additional debt and could restrict our ability to make acquisitions and expand our facilities.

We expect to make capital expenditures of between $125 million and $150 million for the remainder of 2007. For all of 2007, we expect to spend between $425 million and $475 million for the construction of our previously announced ethanol production facilities, the purchase and installation of corn oil extraction equipment, facility maintenance, terminal infrastructure, cellulosic ethanol projects, operational improvements and further development of possible ethanol facility sites. During the nine months ended September 30, 2007, we spent $302.4 million for the purchase of property and equipment, in addition to $44.3 million spent from escrowed cash for the construction of our Charles City facility.

We have no off-balance sheet arrangements.

Critical Accounting Estimates

Our MD&A is based on our condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of financial statements requires the use of estimates and assumptions about matters that are inherently uncertain and that affect the carrying value of our assets and liabilities. We consider an accounting estimate to be critical if:

• the accounting estimate requires us to make assumptions about matters that were highly uncertain at the time the accounting estimate was made; and

• changes in the estimate that are reasonably likely to occur from period to period, or use of different estimates that we reasonably could have used in the current period, would have a material impact on our financial condition or results of operations.

Management has discussed the development and selection of critical accounting estimates with the Audit Committee of our Board of Directors and the Audit Committee has reviewed our MD&A.

Revenue recognition. Revenue from the production of ethanol and its co-products is recorded when title transfers to customers. Shipping and handling charges to customers are included in revenues. In accordance with our prior marketing agreement with Aventine, sales through March 31, 2007 were recorded when products were shipped from our production facilities, net of commissions retained by Aventine at the time payment was remitted. As of April 1, 2007, we commenced direct sales of our ethanol to customers. Our sales of ethanol are now generally recognized upon delivery to our customers at terminals or other locations, rather than upon shipment from our plants, except for sales to Cargill from our plants at Linden, Indiana and Albion, Nebraska, where sales are recognized upon shipment from the plants.

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Derivative instruments and hedging activities. Derivatives are recognized on the balance sheet at their fair value. On the date the derivative contract is entered, we may designate the derivative as a hedge of a forecasted transaction or for the variability of cash flows to be received or paid related to a recognized asset or liability, which we refer to as a “cash flow” hedge. Changes in the fair value of derivatives that are highly effective as, and that are designated and qualify as, a cash flow hedge are recorded in other comprehensive income, net of tax effect, until earnings are affected by the variability of cash flows (e.g., when periodic settlements on a variable rate asset or liability are recorded in earnings). Effectiveness is measured on a quarterly basis using the cumulative dollar offset method.

To reduce price risk caused by market fluctuations, we generally follow a policy of using exchange traded futures contracts to reduce our net position of merchandisable agricultural commodity inventories and forward cash purchase and sales contracts and use exchange traded futures contracts to reduce price risk under fixed price ethanol sales. Forward contracts, in which delivery of the related commodity has occurred, are valued at market price with changes in market price recorded in cost of goods sold. Unrealized gains and losses on forward contracts, in which delivery has not occurred, are deemed “normal purchases and normal sales” under SFAS No. 133, as amended, unless designated otherwise, and therefore are not marked to market in our financial statements. Forward contracts designated otherwise are marked to market.

When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income will be recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with subsequent changes in its fair value recognized in current-period income.

Stock-based compensation. Effective January 1, 2006, we adopted SFAS No. 123R, utilizing the modified prospective application method. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the statement of operations based on their fair values.

We use the Black-Scholes single option pricing model to determine the fair value for employee stock options, which can be affected by our stock price and several subjective assumptions, including:

• expected stock price volatility — since we only recently became a publicly-traded company, we base a portion of this estimate on that of a comparable publicly-traded company;

• expected forfeiture rate — we base this estimate on historic forfeiture rates, which may not be indicative of actual future forfeiture rates; and

• expected term — we base this estimate on the mid-point between the average vesting period and expiration date, which may not equal the actual option term.

If the estimates we use to calculate the fair value for employee stock options differ from actual results, we may be exposed to gains or losses that could be material.

Property and equipment: Property and equipment are stated at cost. Depreciation is computed by the straight-line method over the estimated useful lives set forth below. Changes in circumstances such as technological advances or changes to our business model could result in actual useful lives differing from these estimates.

	Years
Land improvements	10-39
Buildings and improvements	7-40
Machinery and equipment
• Railroad equipment (side track, locomotive and other)	20-39
• Facility equipment (large tanks, fermenters and other equipment)	20-39
• Other	5-7
Office furniture and equipment	3-10

Maintenance, repairs and minor replacements are charged to operations while major replacements and improvements are capitalized.

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Construction in progress will be depreciated upon the commencement of operations of the property.

Goodwill and long-lived assets: The test for goodwill impairment is a two-step process and is performed on at least an annual basis. The first step is a comparison of the fair value of the reporting unit with its carrying amount, including goodwill. If this step reflects impairment, then the loss would be measured in the second step as the excess of recorded goodwill over its implied fair value. Implied fair value is the excess of fair value of the reporting unit over the fair value of all identified assets and liabilities. We test the recoverability of all other long-lived assets, including finite life intangible assets, whenever events or circumstances indicate that the carrying value may not be recoverable. If these other assets were determined to be impaired, the loss would be measured as the amount by which the carrying value of the asset exceeds its fair value. In assessing the recoverability of our long-lived assets, management relies on a number of assumptions including operating results and business strategy. Changes in these factors or changes in the economic environment in which we operate may result in future impairment charges.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following section discusses significant changes in market risks since our latest fiscal year end. You should read this discussion in conjunction with the disclosures made in our Annual Report on Form 10-K for the year ended December 31, 2006 and described in Part II, Item 1A of this quarterly report.

In addition to risks inherent in our operations, as a commodity-based business we are subject to a variety of market factors, including the price relationship between ethanol and corn as shown in the following graph:

(1) Ethanol prices are based on the monthly average of the daily closing price of U.S. average ethanol rack prices quoted by Bloomberg, L.P. The corn prices are based on the monthly average of the daily closing prices of the nearby corn futures quoted by the Chicago Board of Trade (“CBOT”) and assume a conversion rate of 2.8 gallons of ethanol produced per bushel of corn. The comparison between the ethanol and corn prices presented does not reflect the costs of producing ethanol other than the cost of corn and should not be used as a measure of future results. This comparison also does not reflect the revenues received from the sale of distillers grains.

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We consider market risk to be the potential loss arising from adverse changes in market rates and prices. We are subject to significant market risk with respect to the price of ethanol, our principal product, and the price and availability of corn, the principal commodity used in our ethanol production process. In general, ethanol prices are influenced by the supply and demand for gasoline, the availability of substitutes and the effect of laws and regulations. Higher corn costs result in lower profit margins and, therefore, represent unfavorable market conditions. Historically, we have not been able to pass along increased corn costs to our ethanol customers. The availability and price of corn are subject to wide fluctuations due to unpredictable factors such as weather conditions during the corn growing season, carry-over from the previous crop year and current crop year yield, governmental policies with respect to agriculture and international supply and demand. Corn costs represented approximately 59.7% of our total cost of goods sold for the nine months ended September 30, 2007 compared to 46.0% for the nine months ended September 30, 2006. Over the ten-year period from 1997 through 2006, corn prices (based on the CBOT daily futures data) have ranged from a low of $1.75 per bushel on August 11, 2000 to a high of $3.90 per bushel on December 29, 2006 with prices averaging $2.32 per bushel during this period. At November 5, 2007, the CBOT price per bushel of corn for December delivery was $3.75.

Corn prices increased significantly in the fourth quarter of 2006 and have remained in 2007 at substantially higher levels than in 2006. In the first nine months of 2007, CBOT corn prices have ranged from a low of $3.08 per bushel to a high of $4.37 per bushel, with prices averaging $3.67 per bushel, compared to CBOT corn prices in the first nine months of 2006 that ranged from a low of $2.03 per bushel to a high of $2.67 per bushel, with prices averaging $2.34 per bushel. These higher corn prices contributed to adverse comparisons in the three-month and nine-month periods ended September 30, 2007 to the same 2006 period in our cost of goods sold, gross profit, operating income, net income and EBITDA, and we anticipate these higher corn prices will continue to adversely affect such year-over-year comparisons through 2007.

We are also subject to market risk with respect to our supply of natural gas that is consumed in the ethanol production process and has been historically subject to volatile market conditions. Natural gas prices and availability are affected by weather conditions and overall economic conditions. Natural gas costs represented 10.1% of our cost of goods sold for the nine months ended September 30, 2007 compared to 16.6% for the nine months ended September 30, 2006. The price fluctuation in natural gas prices over the seven-year period from December 31, 1999 through December 31, 2006, based on the New York Mercantile Exchange, or NYMEX, daily futures data, has ranged from a low of $1.83 per MMBTU on September 26, 2001 to a high of $15.38 per MMBTU on December 23, 2005, averaging $5.63 per MMBTU during this period. At November 5, 2007, the NYMEX price of natural gas for December delivery was $8.00 per MMBTU.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our corn and natural gas requirements, ethanol contracts and the related exchange-traded contracts for 2006. Market risk related to these factors is estimated as the potential change in pre-tax income, resulting from a hypothetical 10% adverse change in the fair value of our corn and natural gas requirements and ethanol contracts (based on average prices for 2006) net of the corn and natural gas forward and futures contracts used to hedge our market risk with respect to our corn and natural gas requirements. The results of this analysis are set forth in the following table. Actual results may differ from these amounts due to various factors, including significant increases in the Company’s production capacity during 2007.

	Annual Volume Requirements	Units	Hypothetical Adverse Change in Price	Change in Annual Pre-Tax Income
	(In millions)			(In millions)
Ethanol	224.5	gallons	10%	$	(48.9	)
Corn	80.4	bushels	10		(17.4	)
Natural gas	6.9	MMBTU	10		(5.8	)

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As of September 30, 2007, we had contracted forward on a fixed price basis the following quantities of corn and natural gas, which represent the indicated percentages of our estimated requirements for these inputs for the next twelve months:

	Three Months Ending December 31, 2007		Three Months Ending March 31, 2008		Three Months Ending June 30, 2008		Three Months Ending September 30, 2008		Twelve Months Ending September 30, 2008
Corn (thousands of bushels) (1)	—		—		—		—		—
Percentage of estimated requirements	—	%	—	%	—	%	—	%	—	%
Natural Gas (MMBTU)	270,000		—		—		—		270,000
Percentage of estimated requirements	11.0	%	—	%	—	%	—	%	2.7	%

(1) Represents our net corn position, which includes exchange-traded futures and forward purchase contracts. Changes in the value of these contracts are recognized as income or loss in the period in which the change occurs.

The extent to which we enter into these arrangements vary substantially from time to time based on a number of factors, including supply and demand factors affecting the needs of customers or suppliers to purchase ethanol or sell us raw materials on a fixed basis, our views as to future market trends, seasonable factors and the costs of futures contracts. For example, we would expect to purchase forward a smaller percentage of our corn requirements for the fall months when prices tend to be lower.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

We carried out an evaluation at September 30, 2007, under the supervision of our management, including our chief executive officer and our chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on those evaluations, our chief executive officer and chief financial officer have concluded that, as of the end of the period covered by this quarterly report, our disclosure controls and procedures were effective in ensuring that information required to be disclosed in our Exchange Act reports is (1) recorded, processed, summarized and reported in a timely manner, and (2) accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of December 31, 2006, management identified material weaknesses in our internal controls relating to accounting for derivative financial instruments, income taxes and our financial closing process. Our management worked with our Audit Committee to identify and implement corrective actions where required to improve our internal controls, including the enhancement of our reporting systems and procedures. Specifically, we enhanced our process relating to determining the fair value of derivative financial instruments. We also hired an outside service provider to assist us with income tax provisions and increased our tax personnel. Changes made in these areas were determined with the involvement of our Audit Committee, our general counsel, our Chief Financial Officer and our Chief Executive Officer. We believe these actions have remediated our weaknesses relating to accounting for derivative financial instruments and income taxes. We also believe we have taken actions necessary to remediate the remaining weaknesses by focusing additional attention and resources on our financial closing process.

We plan to continue to monitor and improve our processes and plan to hire additional accounting personnel with specific expertise to address our financial reporting requirements. In addition to our recruiting efforts, we expect that work currently underway related to our Sarbanes Oxley Section 404 compliance project will also improve our processes.

Changes in Internal Control over Financial Reporting

Except as noted above, there have been no changes in our internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1A. RISK FACTORS

Our results of operations, financial position and business outlook are highly dependent on commodity prices, which are subject to significant volatility and uncertainty, and the availability of supplies, so our results could fluctuate substantially.

Our results are substantially dependent on commodity prices, especially prices for corn, natural gas, ethanol and unleaded gasoline. As a result of the volatility of the prices for these items, our results may fluctuate substantially and we may experience periods of declining prices for our products and increasing costs for our raw materials, which could result in operating losses. Although we may attempt to offset a portion of the effects of fluctuations in prices by entering into forward contracts to supply ethanol or purchase corn, natural gas or other items or by engaging in transactions involving exchange-traded futures contracts, the amount and duration of these hedging and other risk mitigation activities may vary substantially over time and these activities also involve substantial risks. See “We engage in hedging transactions and other risk mitigation strategies that could harm our results.”

Our business is highly sensitive to corn prices and we generally cannot pass on increases in corn prices to our customers.

The principal raw material we use to produce ethanol and co-products, including dry and wet distillers grains, is corn. As a result, changes in the price of corn can significantly affect our business. In general, rising corn prices produce lower profit margins. Because ethanol competes with non-corn-based fuels, we generally are unable to pass along increased corn costs to our customers. At certain levels, corn prices may make ethanol uneconomical to use in fuel markets. Corn costs constituted approximately 59.7% of our total cost of goods sold for the nine months ended September 30, 2007, compared to 46.0% for the nine months ended September 30, 2006. Over the ten-year period from 1997 through 2006, corn prices (based on the Chicago Board of Trade (the “CBOT”) daily futures data)

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have ranged from a low of $1.75 per bushel on August 11, 2000 to a high of $3.90 per bushel on December 29, 2006, with prices averaging $2.32 per bushel during this period. At November 5, 2007, the CBOT price per bushel of corn for December delivery was $3.75.

The industry has experienced significantly higher corn prices commencing in the fourth quarter of 2006, which have remained in 2007 at substantially higher levels than in 2006. In the nine months of 2007, CBOT corn prices have ranged from a low of $3.08 per bushel to a high of $4.37 per bushel, with prices averaging $3.67 per bushel. These higher corn prices contributed to adverse comparisons in the three-month and nine-month period ended September 30, 2007 to the same 2006 periods in our cost of goods sold, gross profit, operating income, net income and EBITDA, and we anticipate these higher corn prices will continue to adversely affect such year-over-year comparisons through 2007.

The price of corn is influenced by weather conditions and other factors affecting crop yields, farmer planting decisions and general economic, market and regulatory factors. These factors include government policies and subsidies with respect to agriculture and international trade, and global and local demand and supply. The significance and relative effect of these factors on the price of corn is difficult to predict. Any event that tends to negatively affect the supply of corn, such as adverse weather or crop disease, could increase corn prices and potentially harm our business. We may also have difficulty, from time to time, in physically sourcing corn on economical terms due to supply shortages. Such a shortage could require us to suspend operations until corn is available at economical terms, which would have a material adverse effect on our business, results of operations and financial position. In addition, the price we pay for corn at a facility could increase if an additional ethanol production facility is built in the same general vicinity.

The spread between ethanol and corn prices can vary significantly and may not return to recent high levels.

Our gross margin depends principally on the spread between ethanol and corn prices. During the five-year period from 2002 through 2006, ethanol prices (based on average U.S. ethanol rack prices from Bloomberg (“Bloomberg”)) have ranged from a low of $0.94 per gallon to a high of $3.98 per gallon, averaging $1.70 per gallon during this period. For the year ended December 31, 2006, ethanol prices averaged $2.53 per gallon, reaching a high of $3.98 per gallon and a low of $1.72 per gallon (based on the daily closing prices from Bloomberg). In early 2006, the spread between ethanol and corn prices was at historically high levels, driven in large part by oil companies removing a competitive product, MTBE, from the fuel stream and replacing it with ethanol in a relatively short time period. However, this spread has fluctuated widely and narrowed significantly during 2007. Fluctuations are likely to continue to occur. Any reduction in the spread between ethanol and corn prices, whether as a result of an increase in corn prices or natural gas prices or a reduction in ethanol prices, would adversely affect our results of operations and financial position. Further, it is possible that ethanol prices could decline below our marginal cost of production, which could cause us to suspend production of ethanol at some or all of our facilities.

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

We rely upon third parties for our supply of natural gas, which is consumed in the manufacture of ethanol. The prices for and availability of natural gas are subject to volatile market conditions. These market conditions often are affected by factors beyond our control such as higher prices resulting from colder than average weather conditions and overall economic conditions. Significant disruptions in the supply of natural gas could impair our ability to manufacture ethanol for our customers. Furthermore, increases in natural gas prices or changes in our natural gas costs relative to natural gas costs paid by competitors may adversely affect our results of operations and financial position. Natural gas costs represented approximately 10.1% of our cost of goods sold for the nine months ended September 30, 2007, compared to 16.6% for the nine months ended September 30, 2006. The price fluctuations in natural gas prices over the seven-year period from December 31, 1999 through December 31, 2006, based on the New York Mercantile Exchange, or NYMEX, daily futures data, has ranged from a low of $1.83 per MMBTU on September 26, 2001 to a high of $15.38 per MMBTU on December 13, 2005, averaging $5.63 per MMBTU during this period. At November 5, 2007, the NYMEX price of natural gas for December delivery was $8.00 per MMBTU.

Fluctuations in the selling price and production cost of gasoline may reduce our profit margins.

Ethanol is marketed both as an important gasoline component to reduce vehicle emissions from gasoline and as an octane enhancer to improve the octane rating of gasoline with which it is blended. As a result, ethanol prices are influenced by the supply and demand for gasoline and our results of operations and financial position may be materially adversely affected if gasoline demand or prices decrease.

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Historically, the price of a gallon of gasoline has been lower than the cost to produce a gallon of ethanol. In addition, some of our sales contracts provide for pricing on an indexed basis, so that the price we receive for products sold under these arrangements is adjusted as gasoline prices change.

We may not realize the expected benefits from the ethanol facilities acquired from ASAlliances Biofuels, LLC in the time frame anticipated or at all.

The expected benefits of our acquisition of three ethanol facilities from ASAlliances Biofuels, LLC will depend, in part, on the timely construction and operation of the acquired ethanol facilities, which involve the following risks, among others:

• Failure of contractors to meet construction milestones; and

• Our inability to achieve the expected production schedules of the acquired ethanol facilities.

The expected benefits of the transaction also depend on the timely and efficient integration of the operations and personnel of the acquired ethanol facilities. The risks involved in this integration include, among others:

• Disruption of our ongoing business and distraction of management;

• Loss of key employees of the acquired ethanol facilities; and

• Loss of, or disputes with, existing service providers and suppliers of the acquired ethanol facilities.

We may also encounter unforeseen obstacles or costs in the timely construction and operation of the acquired ethanol facilities and the integration of such ethanol facilities. The presence of one or more material liabilities of the acquired ethanol facilities that are unknown to us at the time of acquisition may have a material adverse effect on our business.

We are also dependent on Cargill and its subsidiaries for various services at the acquired ethanol facilities, including corn procurement, the marketing and sale of ethanol and distillers grains produced at the facilities and risk management. As a result, our results of operations and financial position may be adversely affected if Cargill does not perform these services in an effective manner.

We may be required to write down the value of our goodwill.

As of September 30, 2007, we had $192.5 million of goodwill resulting from the ASA Acquisition. Current accounting rules require that goodwill and certain intangible assets be assessed for impairment using fair value measurement techniques. If the carrying amount of a reporting unit exceeds its fair value, then a goodwill impairment test is performed to measure the amount of the impairment loss, if any. The goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as in a business combination. Determining the fair value of the implied goodwill is judgmental in nature and often involves the use of significant estimates and assumptions. These estimates and assumptions could have a significant impact on whether or not an impairment charge is recognized and also the magnitude of any such charge. Estimates of fair value are primarily determined using discounted cash flows and market comparisons. These approaches use significant estimates and assumptions, including projection and timing of future cash flows, discount rates reflecting the risk inherent in future cash flows, perpetual growth rates, determination of appropriate market comparables, and determination of whether a premium or discount should be applied to comparables. The plans and estimates used to value these assets may be incorrect. If our actual results are worse than the plans and estimates we used to assess the recoverability of ASA assets in connection with the ASA Acquisition, or our plans and estimates are otherwise incorrect, we could incur impairment charges relating to the goodwill resulting from the ASA Acquisition, including up to the full $192.5 million of goodwill.

Our business is subject to seasonal fluctuations.

Our operating results are influenced by seasonal fluctuations in the price of our primary operating inputs, corn and natural gas, and the price of our primary product, ethanol. The spot price of corn tends to rise during the spring planting season in May and June and

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tends to decrease during the fall harvest in October and November. The price for natural gas, however, tends to move opposite that of corn and tends to be lower in the spring and summer and higher in the fall and winter. In addition, our ethanol prices are substantially correlated with the price of unleaded gasoline especially in connection with any indexed, gas-plus sales contracts we may have. The price of unleaded gasoline tends to rise during each summer and winter. Given our limited history and the growth of our industry, we do not know yet how these seasonal fluctuations will affect our results over time.

We engage in hedging transactions and other risk mitigation strategies that could harm our results of operations.

In an attempt to partially offset the effects of volatility of ethanol prices and corn and natural gas costs, we enter into contracts to supply a portion of our ethanol production or purchase a portion of our corn or natural gas requirements on a forward basis and also engage in other hedging transactions involving exchange-traded futures contracts for corn, natural gas and unleaded gasoline from time to time. The price of unleaded gasoline also affects the price we receive for our ethanol under indexed contracts. The financial statement impact of these activities is dependent upon, among other things, the prices involved and our ability to sell sufficient products to use all of the corn and natural gas for which we have futures contracts. Hedging arrangements also expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or, in the case of exchange-traded contracts, where there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices paid or received by us. Hedging activities can themselves result in losses when a position is purchased in a declining market or a position is sold in a rising market. A hedge position is often settled in the same time frame as the physical commodity is either purchased (corn and natural gas) or sold (ethanol). Hedging losses may be offset by a decreased cash price for corn and natural gas and an increased cash price for ethanol. We also vary the amount of hedging or other risk mitigation strategies we undertake, and we may choose not to engage in hedging transactions at all. As a result, our results of operations and financial position may be adversely affected by increases in the price of corn or natural gas or decreases in the price of ethanol or unleaded gasoline.

We may become in default under the Senior Credit Facility as a result of actions of third parties that are unrelated to our business.

The Senior Credit Facility contains customary events of default and also includes events of default based on certain actions by Fagan, the design-builder of the Linden, Albion and Bloomingburg facilities, Cargill, and other third parties that provide goods and services to the facilities, including actions that are unrelated to the construction and operation of the facilities. In particular, the material breach by any such third parties of their agreements relating to the facilities, the failure of any such third parties to pay their indebtedness, including trade payables, and the entry of material judgments or the occurrence of an insolvency event with respect to any such third party would constitute an event of default under the Senior Credit Facility. We have no control over such third parties and could experience an event of default with no ability to cure the default. In that event, the lenders could demand payment of all indebtedness outstanding under the Senior Credit Facility under circumstances where alternative financing may be unavailable or available on unfavorable terms. If we were unable to obtain alternative financing to pay the Senior Credit Facility, the lenders could foreclose on the Linden, Albion, and Bloomingburg facilities and we could lose our investment in those facilities.

We may not achieve anticipated operating results and our financial position may be adversely affected if we do not successfully develop our corn oil extraction business.

Our anticipated operating results and financial position may depend in part on our ability to develop and operate our planned corn oil extraction facilities successfully. We plan to extract corn oil from distillers grains, a co-product of the ethanol production process, and to sell the oil or convert it into biodiesel. We have contracted with Crown Iron Works Company for the purchase of corn oil extraction equipment. Large scale extraction of corn oil from distillers grains, as we contemplate, is unproven, and we may not achieve planned operating results. Our operating results and financial position will be affected by events or conditions associated with the development, operation and cost of the planned corn oil extraction equipment, including:

• the outcome of negotiations with government agencies, vendors, customers or others, including, for example, our ability to negotiate favorable contracts with customers, or the development of reliable markets;

• changes in development and operating conditions and costs, including costs of services, equipment and construction;

• unforeseen technological difficulties, including problems that may delay startup or interrupt production or that may lead to unexpected downtime, or construction delays;

• corn prices and other market conditions, including competition from other producers of corn oil;

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• government regulation; and

• development of transportation, storage and distribution infrastructure supporting the facilities and the biodiesel industry generally.

We are subject to and will become subject to additional financial reporting and other requirements for which our accounting, internal audit and other management systems and resources may not be adequately prepared.

We are subject to and will become subject to additional reporting and other obligations under the Securities Exchange Act of 1934, as amended, including the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 no later than December 31, 2007. Section 404 requires annual management assessment of the effectiveness of our internal controls over financial reporting and a report by our independent auditors addressing these assessments. These reporting and other obligations will increasingly place significant demands on our management, administrative, operational, internal audit, tax and accounting resources. We are implementing additional financial and management controls, reporting systems and procedures and an internal audit function and are hiring additional accounting, internal audit and finance staff. If we are unable to accomplish these objectives in a timely and effective fashion, our ability to comply with our financial reporting requirements and other rules that apply to reporting companies could be impaired. In connection with the audit of our financial statements for the fiscal year ended December 31, 2006, we identified several material weaknesses in our internal controls over financial reporting relating to inadequate monitoring of accounting recognition matters and significant accounting estimates, including derivative financial instruments and income taxes, and deficiencies in our financial closing process. We have remediated these weaknesses, but we cannot assure you that we will have no future deficiencies or weaknesses in our internal controls over financial reporting.

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

Most of our revenues are and will continue to be derived from the sale of ethanol and the related co-products that we produce at our facilities. Our operations may be subject to significant interruption if any of our facilities experiences a major accident or is damaged by severe weather or other natural disasters. In addition, our operations may be subject to labor disruptions and unscheduled downtime, or other operational hazards inherent in our industry, such as equipment failures, fires, explosions, abnormal pressures, blowouts, pipeline ruptures, transportation accidents and natural disasters. Some of these operational hazards may cause personal injury or loss of life, severe damage to or destruction of property and equipment or environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. Our insurance may not be adequate to fully cover the potential operational hazards described above and we may not be able to renew this insurance on commercially reasonable terms or at all.

We may not be able to implement our expansion strategy as planned or at all.

We plan to grow our business by investing in new or existing facilities and to pursue other business opportunities, such as marketing VE85^TM and other ethanol-blended fuel. We believe that there is increasing competition for suitable facility sites. We may not find suitable additional sites for construction of new facilities or other suitable expansion opportunities.

We may need additional financing to implement our expansion strategy and we may not have access to the funding required for the expansion of our business or such funding may not be available to us on acceptable terms. We may finance the expansion of our business with additional indebtedness or by issuing additional equity securities. We could face financial risks associated with incurring additional indebtedness, such as reducing our liquidity and access to financial markets and increasing the amount of cash flow required to service such indebtedness.

We must also obtain numerous regulatory approvals and permits in order to construct and operate additional or expanded facilities, including our Hartley, Welcome, Bloomingburg and Reynolds facilities. These requirements may not be satisfied in a timely manner or at all. In addition, as described below under “We may be adversely affected by environmental, health and safety laws, regulations and liabilities,” federal and state governmental requirements may substantially increase our costs, which could have a material adverse effect on our results of operations and financial position. Our expansion plans may also result in other unanticipated adverse consequences, such as the diversion of management’s attention from our existing operations.

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Our construction costs may also increase to levels that would make a new facility too expensive to complete or unprofitable to operate. Our construction contracts with respect to the construction of our facilities generally do not limit our exposure to higher costs. Contractors, engineering firms, construction firms and equipment suppliers also receive requests and orders from other ethanol companies and, therefore, we may not be able to secure their services or products on a timely basis or on acceptable financial terms. We may suffer significant delays or cost overruns as a result of a variety of factors, such as shortages of workers or materials, transportation constraints, adverse weather, unforeseen difficulties or labor issues, any of which could prevent us from commencing operations as expected at our facilities.

Our expansion strategy also depends on prevailing market conditions for the price of ethanol and the costs of corn and natural gas and our expectations of future market conditions. We recently suspended construction of our Reynolds facility due to market conditions. If market conditions do not improve as anticipated, we could lose our investment in this facility and could incur additional costs associated with terminating various construction contracts. We also may not proceed with construction at other development sites and could incur losses associated our investments in those sites.

Additionally, any expansion of our existing facilities or any installation of corn oil extraction system at one of our existing facilities would be sufficiently novel and complex that we may not be able to complete either successfully or without incurring significant cost overruns and construction delays. We have only limited experience with facility expansion and we have never installed large-scale, corn oil extraction systems at our facilities.

Accordingly, we may not be able to implement our expansion strategy as planned or at all. We may not find additional appropriate sites for new facilities and we may not be able to finance, construct, develop or operate these new or expanded facilities successfully.

Potential future acquisitions could be difficult to find and integrate, divert the attention of key personnel, disrupt our business, and adversely affect our financial results.

As part of our business strategy, we may consider acquisitions of building sites, production facilities, storage or distribution facilities and selected infrastructure. We may not find suitable acquisition opportunities.

Acquisitions involve numerous risks, any of which could harm our business, including:

• difficulties in integrating the operations, technologies, products, existing contracts, accounting processes and personnel of the target and realizing the anticipated synergies of the combined businesses;

• difficulties in building an ethanol plant on a site we purchase, including obtaining zoning and other required permits;

• risks relating to environmental hazards on sites we purchase;

• risks relating to acquiring or developing the infrastructure needed for facilities or sites we may acquire, including access to rail networks;

• difficulties in supporting and transitioning customers, if any, of the target company or assets;

• diversion of financial and management resources from existing operations;

• the price we pay or other resources that we devote may exceed the value we realize, or the value we could have realized if we had allocated the purchase price or other resources to another opportunity;

• risks of entering new markets or areas in which we have limited or no experience or are outside our core competencies;

• potential loss of key employees, customers and strategic alliances from either our current business or the business of the target;

• assumption of unanticipated problems or latent liabilities, such as problems with the quality of the products of the target; and

• inability to generate sufficient revenue to offset acquisition costs and development costs.

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Acquisitions also frequently result in the recording of goodwill and other intangible assets which are subject to potential impairments, periodic amortization, or both that could harm our financial results. As a result, if we fail to properly evaluate acquisitions or investments, we may not achieve the anticipated benefits of any such acquisitions, and we may incur costs in excess of what we anticipate. The failure to successfully evaluate and execute acquisitions or investments or otherwise adequately address these risks could materially harm our business and financial results.

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

Substantial development of infrastructure will be required by persons and entities outside of our control for our operations, and the ethanol industry generally, to grow. Areas requiring expansion include, but are not limited to:

• rail capacity;

• storage facilities for ethanol;

• truck fleets capable of transporting ethanol within localized markets;

• refining and blending facilities to handle ethanol;

• service stations equipped to handle ethanol fuels; and

• the fleet of Flexible Fuel Vehicles, or FFVs, capable of using E85 fuel.

Substantial investments required for these infrastructure changes and expansions may not be made or they may not be made on a timely basis. Any delay or failure in making the changes to or expansion of infrastructure could hurt the demand or prices for our products, impede our delivery of products, impose additional costs on us or otherwise have a material adverse effect on our results of operations or financial position. Our business is dependent on the continuing availability of infrastructure and any infrastructure disruptions could have a material adverse effect on our business.

We have a limited operating history and our business may not be as successful as we envision.

We began our business in 2001, and our operating facilities have less than five years of commercial operations. Accordingly, we have a limited operating history from which you can evaluate our business and prospects. In addition, our prospects must be considered in light of the risks and uncertainties encountered by a company with limited operating history in rapidly evolving markets, such as the ethanol market, where supply and demand may change significantly in a short amount of time.

Some of these risks relate to our potential inability to:

• effectively manage our business and operations;

• successfully execute our plan to sell our ethanol directly to customers;

• recruit and retain key personnel;

• successfully maintain a low-cost structure as we expand the scale of our business;

• manage rapid growth in personnel and operations;

• develop new products that complement our existing business; and

• successfully address the other risks described throughout this report.

If we cannot successfully address these risks, our business and our results of operations and financial position would suffer.

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New plants under construction or decreases in the demand for ethanol may result in excess production capacity in our industry.

According to the RFA, domestic ethanol production capacity will have increased from 1.8 BGY as of January 2001 to more than seven billion gallons by the end of 2007. The RFA estimates that, as of November 1, 2007, approximately 6.4 BGY of additional production capacity is under construction. The ethanol industry in the U.S. now consists of more than 130 production facilities. Excess capacity in the ethanol industry would have an adverse effect on our results of operations, cash flows and financial position. In a manufacturing industry with excess capacity, producers have an incentive to manufacture additional products for so long as the price exceeds the marginal cost of production (i.e., the cost of producing only the next unit, without regard for interest, overhead or fixed costs). This incentive can result in the reduction of the market price of ethanol to a level that is inadequate to generate sufficient cash flow to cover costs.

Excess capacity may also result from decreases in the demand for ethanol, which could result from a number of factors, including, but not limited to, regulatory developments and reduced U.S. gasoline consumption. Reduced gasoline consumption could occur as a result of increased prices for gasoline or crude oil, which could cause businesses and consumers to reduce driving or acquire vehicles with more favorable gasoline mileage. There is some evidence that this has occurred in the recent past as U.S. gasoline prices have increased.

We may not be able to compete effectively in our industry.

In the U.S., we compete with other corn processors, ethanol producers and refiners, including Archer Daniels Midland Company, POET, LLC, US BioEnergy Corporation, Hawkeye Renewables, LLC, Aventine Renewable Energy Holdings, Inc., and Cargill. As of November 1, 2007, the top five producers accounted for approximately 46% of the ethanol production capacity in the U.S. according to the RFA. A number of our competitors are divisions of substantially larger enterprises and have substantially greater financial resources than we do. Smaller competitors also pose a threat. Farmer-owned cooperatives and independent firms consisting of groups of individual farmers and investors have been able to compete successfully in the ethanol industry. These smaller competitors operate smaller facilities that do not affect the local price of corn grown in the proximity of the facility as much as larger facilities like ours do. In addition, many of these smaller competitors are farmer owned and often require their farmer-owners to commit to selling them a certain amount of corn as a requirement of ownership. A significant portion of production capacity in our industry consists of smaller-sized facilities. Most new ethanol plants under development across the country are individually owned. In addition, institutional investors and high net worth individuals could heavily invest in ethanol production facilities and oversupply the demand for ethanol, resulting in lower ethanol price levels that might adversely affect our results of operations and financial position.

In addition to domestic competition, we also face increasing competition from international suppliers. Currently there is a $0.54 per gallon tariff on foreign produced ethanol which is scheduled to expire January 1, 2009. If this tariff is not renewed, we would face increased competition from international suppliers. Ethanol imports equivalent up to 7% of total domestic production in any given year from various countries were exempted from this tariff under the Caribbean Basin Initiative to spur economic development in Central America and the Caribbean. Currently, international suppliers produce ethanol primarily from sugar cane and have cost structures that may be substantially lower than ours.

Any increase in domestic or foreign competition could cause us to reduce our prices and take other steps to compete effectively, which could adversely affect our results of operations and financial position.

Our operating results may suffer if our direct marketing and sales efforts are not effective.

On March 31, 2007 we terminated our agreements with Aventine regarding the marketing and sale of our ethanol and, on April 1, 2007, we commenced direct sales of our ethanol to customers. In connection with this activity, we have established our own marketing, transportation and storage infrastructure. We lease tanker railcars and have contracted with storage depots near our customers and at our strategic locations for efficient delivery of our finished ethanol product. We have also hired a marketing and sales force, as well as logistical and other operational personnel to staff our distribution activities. The marketing, sales, distribution, transportation, storage or administrative efforts we have implemented may not achieve results comparable to those achieved by marketing through Aventine. Any failure to successfully execute these efforts would have a material adverse effect on our results of operations and financial position. Our financial results in 2007 also may be adversely affected by our need to establish inventory in storage locations to facilitate this transition.

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Further, ethanol produced at our Linden, Albion and Bloomingburg facilities is or will be marketed by Cargill under agreements that remained in place after closing of the ASA Acquisition. We compete with Cargill for sales of ethanol and distillers grains. Our direct marketing and sales efforts may be less efficient as a result of the marketing relationship we have with Cargill for a portion of our production.

Operations at our new facilities and our additional planned facilities are subject to various uncertainties, which may cause them to not achieve results comparable to our Aurora and Fort Dodge facilities.

Test operations began at our Fort Dodge facility in September 2005. During this time, a failure occurred in a key piece of equipment. This failure, which has been remedied by installation of replacement equipment from a new supplier, delayed our startup process. In October 2005, we recommenced our startup activities at the plant and are now operating at full capacity. As new plants, our Charles City, Linden and Albion facilities are subject, and our additional planned facilities will be subject, to various uncertainties as to their ability to produce ethanol and co-products as planned, including the potential for additional failures of key equipment. Due to these uncertainties, the results of our new facilities or our additional planned facilities may not be comparable to those of our Aurora, Fort Dodge and Charles City facilities.

The U.S. ethanol industry is highly dependent upon federal and state legislation and regulation and any changes in legislation or regulation could materially and adversely affect our results of operations and financial position.

The elimination or significant reduction in the blenders’ credit could have a material adverse effect on our results of operations and financial position. The cost of production of ethanol is made significantly more competitive with regular gasoline by federal tax incentives. Before January 1, 2005, the federal excise tax incentive program allowed gasoline distributors who blended ethanol with gasoline to receive a federal excise tax rate reduction for each blended gallon they sold. If the fuel was blended with 10% ethanol, the refiner/marketer paid $0.052 per gallon less tax, which equated to an incentive of $0.52 per gallon of ethanol. The $0.52 per gallon incentive for ethanol was reduced to $0.51 per gallon in 2005 and is scheduled to expire in 2010. The blenders’ credits could be eliminated or reduced at any time through an act of Congress and may not be renewed in 2010 or may be renewed on different terms. In addition, the blenders’ credits, as well as other federal and state programs benefiting ethanol (such as tariffs), generally are subject to U.S. government obligations under international trade agreements, including those under the World Trade Organization Agreement on Subsidies and Countervailing Measures, and might be the subject of challenges thereunder, in whole or in part. The elimination or significant reduction in the blenders’ credit or other programs benefiting ethanol may have a material adverse effect on our results of operations and financial position.

Ethanol can be imported into the U.S. duty-free from some countries, which may undermine the ethanol industry in the U.S. Imported ethanol is generally subject to a $0.54 per gallon tariff that was designed to offset the $0.51 per gallon ethanol incentive available under the federal excise tax incentive program for refineries that blend ethanol in their fuel. A special exemption from the tariff exists for ethanol imported from 24 countries in Central America and the Caribbean Islands, which is limited to a total of 7% of U.S. production per year. Imports from the exempted countries may increase as a result of new plants under development. Since production costs for ethanol in these countries are estimated to be significantly less than what they are in the U.S., the duty-free import of ethanol through the countries exempted from the tariff may negatively affect the demand for domestic ethanol and the price at which we sell our ethanol. Although the $0.54 per gallon tariff has been extended through December 31, 2008, bills were previously introduced in both the U.S. House of Representatives and U.S. Senate to repeal the tariff. We do not know the extent to which the volume of imports would increase or the effect on U.S. prices for ethanol if the tariff is not renewed beyond its current expiration. Any changes in the tariff or exemption from the tariff could have a material adverse effect on our results of operations and financial position. In addition, the North America Free Trade Agreement, or NAFTA, which entered into force on January 1, 1994, allows Canada and Mexico to export ethanol to the United States duty-free or at a reduced rate. Canada is exempt from duty under the current NAFTA guidelines, while Mexico’s duty rate is $0.10 per gallon.

The effect of the RFS in the Energy Policy Act of 2005 is uncertain. The Acts eliminated the mandated use of oxygenates and established minimum nationwide levels of renewable fuels (ethanol, biodiesel or any other liquid fuel produced from biomass or biogas) to be included in gasoline. The elimination of the oxygenate requirement for reformulated gasoline may result in a decline in ethanol consumption, which in turn could have a material adverse effect on our results of operations and financial condition. The legislation also included provisions for trading of credits for use of renewable fuels and authorized potential reductions in the RFS minimum by action of a governmental administrator.

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The mandated minimum level of use of renewable fuels in the RFS is significantly below projected ethanol production levels. Excess production capacity in our industry would negatively affect our results of operations, financial position and cash flows. See “New plants under construction or decreases in the demand for ethanol may result in excess production capacity in our industry.”

Waivers of the RFS minimum levels of renewable fuels included in gasoline could have a material adverse affect on our results of operations. Under the Energy Policy Act of 2005, the U.S. Department of Energy, in consultation with the Secretary of Agriculture and the Secretary of Energy, may waive the renewable fuels mandate with respect to one or more states if the Administrator of the U.S. Environmental Protection Agency, or U.S. “EPA”, determines that implementing the requirements would severely harm the economy or the environment of a state, a region or the U.S., or that there is inadequate supply to meet the requirement. Any waiver of the RFS with respect to one or more states would adversely offset demand for ethanol and could have a material adverse effect on our results of operations and financial condition.

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

We are subject to various federal, state and local environmental laws and regulations, 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. In addition, some of these laws and regulations require our facilities to operate under permits that are subject to renewal or modification. These laws, regulations and permits can often require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment. A violation of these laws and regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns. In addition, we have made, and expect to make, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits.

We may be liable 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 arrange for the disposal of hazardous substances. If these substances have been or are disposed of or released at sites that undergo investigation and/or remediation by regulatory agencies, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, or other environmental laws for all or part of the costs of investigation and/or remediation, and for damages to natural resources. We may also be subject to related claims by private parties alleging property damage and personal injury due to exposure to hazardous or other materials at or from those properties. Some of these matters may require us to expend significant amounts for investigation, cleanup or other costs.

In addition, new laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make additional significant expenditures. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls at our production facilities. Present and future environmental laws and regulations (and interpretations thereof) applicable to our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our results of operations and financial position.

The hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, and abnormal pressures and blowouts) may also result in personal injury claims or damage to property and third parties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, we could sustain losses for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. Events that result in significant personal injury or damage to our property or third parties or other losses that are not fully covered by insurance could have a material adverse effect on our results of operations and financial position.

We are dependent upon our officers for management and direction, and the loss of any of these persons could adversely affect our operations and results.

We are dependent upon our officers for implementation of our proposed expansion strategy and execution of our business plan. The loss of any of our officers could have a material adverse effect upon our results of operations and financial position. We do not have employment agreements with our officers or other key personnel. In addition, we do not maintain “key person” life insurance for any of our officers. The loss of any of our officers could delay or prevent the achievement of our business objectives.

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Our competitive position, financial position and results of operations may be adversely affected by technological advances and our efforts to anticipate and employ such technological advances may prove unsuccessful.

The development and implementation of new technologies may result in a significant reduction in the costs of ethanol production. For instance, any technological advances in the efficiency or cost to produce ethanol from inexpensive, cellulosic sources such as wheat, oat or barley straw could have an adverse effect on our business, because our facilities are designed to produce ethanol from corn, which is, by comparison, a raw material with other high value uses. We do not predict when new technologies may become available, the rate of acceptance of new technologies by our competitors or the costs associated with new technologies. In addition, advances in the development of alternatives to ethanol could significantly reduce demand for or eliminate the need for ethanol.

We plan to invest over time on projects and companies engaged in research, development and commercialization of processes for conversion of cellulosic material to ethanol. These investments will be early- and mid-stage and highly speculative. The use of cost-effective and efficient cellulosic material in the production of ethanol is unproven. There is no assurance when, if ever, commercially viable technology will be developed. Nor can there be any assurance that we can identify suitable investment opportunities, that such development will be the product of any investment we make in this technology and that we will not lose our investments in whole or in part, or that if developed by others it will be available to producers such as us on commercially reasonable terms.

Any advances in technology which require significant unanticipated capital expenditures to remain competitive or which reduce demand or prices for ethanol would have a material adverse effect on our results of operations and financial position.

Insiders control a significant portion of our common stock and their interests may differ from those of other shareholders.

As of November 5, 2007, our executive officers and directors as a group beneficially own approximately 38.7% of our outstanding common stock, including Donald L. Endres, our Chief Executive Officer, who beneficially owns approximately 35.4% of our outstanding common stock. The interests of these shareholders may not always coincide with our interests as a company or the interests of other shareholders. The sale or prospect of sale of a substantial number of the shares could have an adverse effect on the market price of our common stock.

Our debt level could negatively impact our financial condition, results of operations and business prospects.

As of September 30, 2007, our total debt was $879.3 million (net of unaccreted discount of $3.1 million). Under agreements governing our debt, we may be able to incur a significant amount of additional debt from time to time, including drawing under our credit agreement and Senior Credit Facility. If we do so, the risks related to our high level of debt could increase. Specifically, our high level of debt could have important consequences to our shareholders, including the following:

• requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

• limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;

• limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• increasing our vulnerability to both general and industry-specific adverse economic conditions; and

• placing us at a competitive disadvantage against less leveraged competitors.

Some of our debt bears interest at variable rates and exposes us to interest rate risk. If interest rates increase, our debt service obligations with respect to the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Our common stock price has been volatile and you may lose all or part of your investment.

The market price of our common stock has fluctuated significantly since our IPO. Future fluctuations could be based on various factors in addition to those otherwise described in this report, including:

• our operating performance and the performance of our competitors;

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• the public’s reaction to our press releases, our other public announcements and our filings with the SEC;

• changes in earnings estimates or recommendations by research analysts who follow us or other companies in our industry;

• variations in general economic conditions;

• the registration rights granted by us with respect to shares of our common stock that were issued in connection with our acquisition from ASAlliances Biofuels, LLC;

• the number of shares that are publicly traded;

• actions of our existing shareholders, including sales of common stock by our directors and executive officers;

• the arrival or departure of key personnel; and

• other developments affecting us, our industry or our competitors.

In addition, in recent years the stock market has experienced significant price and volume fluctuations. These fluctuations may be unrelated to the operating performance of particular companies. These broad market fluctuations may cause declines in the market price of our common stock. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company or its performance, and those fluctuations could materially reduce our common stock price.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In connection with acquiring the land rights for the site for our Litchfield, Illinois facility, we issued to an affiliate of American Milling 150,000 share of our common stock in July 2007 and an additional 150,000 shares in September 2007. These issuances were made for site location and evaluation services pursuant to the site acquisition agreement we have with American Milling. We relied on the private offering exemption under Section 4(2) of the Securities Act of 1933 to complete this transaction.

In connection with the ASA Acquisition, on August 17, 2007 we issued an aggregate of 13,801,384 shares of common stock, to the security holders named in the Unit Purchase Agreement. We relied on the private offering exemption under Section 4(2) of the Securities Act of 1933 to complete this transaction.

ITEM 6. EXHIBITS

2.1	Unit Purchase Agreement among VeraSun Energy Corporation, ASA OpCo Holdings, LLC, ASAlliances Biofuels, LLC and the Securityholders named therein (incorporated by reference to Exhibit 2.1 to VeraSun Energy Corporation’s current report on Form 8-K filed on July 25, 2007).
3.1	Articles of Incorporation, as amended, of VeraSun Energy Corporation.*
3.2	Amended and Restated Bylaws of VeraSun Energy Corporation (incorporated by reference to Exhibit 3.1 to VeraSun Energy Corporation’s current report on Form 8-K filed on May 17, 2007).
4.1	Indenture, dated as of December 21, 2005, between VeraSun Energy Corporation, as Issuer, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC and VeraSun Marketing, LLC, as Subsidiary Guarantors, and Wells Fargo, N.A., as Trustee.*
4.2	Registration Rights Agreement, dated as of December 21, 2005, by and among VeraSun Energy Corporation, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Marketing LLC, Lehman Brothers Inc. and Morgan Stanley & Co. Incorporated.*
4.3	First Supplemental Indenture, dated May 4, 2006, between VeraSun Energy Corporation, as Issuer, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Marketing, LLC and VeraSun Welcome, LLC, as Subsidiary Guarantors, and Wells Fargo, N.A., as Trustee.*
4.4	Second Supplemental Indenture, dated August 21, 2006, between VeraSun Energy Corporation, as Issuer, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Hartley, LLC, VeraSun Marketing, LLC, and VeraSun Welcome, LLC, as Subsidiary Guarantors, and Wells Fargo, N.A., as Trustee (incorporated by reference to Exhibit 10.1 to VeraSun Energy Corporation’s quarterly report on form 10-Q for the period ending September 30, 2006).

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4.5	Third Supplemental Indenture, dated February 9, 2007, between VeraSun Energy Corporation, as Issuer, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Hartley, LLC, VeraSun Marketing, LLC, VeraSun Welcome, LLC, VeraSun Granite City, LLC, and VeraSun Reynolds, LLC, as Subsidiary Guarantors, and Wells Fargo, N.A., as Trustee (incorporated by reference to Exhibit 10.1 to VeraSun Energy Corporation’s annual report on form 10-K for the period ending December 30, 2006).
4.6	Fourth Supplemental Indenture, dated May 17, 2007, between VeraSun Energy Corporation as Issuer, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Hartley, LLC, VeraSun Marketing, LLC, VeraSun Welcome, LLC, VeraSun Granite City, LLC, VeraSun Reynolds, LLC, and VeraSun Biodiesel, LLC, as subsidiary Guarantors, and Wells Fargo, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to VeraSun Energy Corporation’s current report on Form 8-K filed on May 17, 2007).
4.7	Indenture, dated as of May 16, 2007, between VeraSun Energy Corporation as Issuer, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Hartley, LLC, VeraSun Marketing, LLC, VeraSun Welcome, LLC, VeraSun Granite City, LLC, VeraSun Reynolds, LLC, and VeraSun Biodiesel, LLC, as subsidiary Guarantors, and Wells Fargo, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to VeraSun Energy Corporation’s current report on Form 8-K filed on May 17, 2007).
4.8	Registration Rights Agreement, dated as of May 16, 2007, between VeraSun Energy Corporation, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC, VeraSun Charles City, LLC, VeraSun Hartley, LLC, VeraSun Marketing, LLC, VeraSun Welcome, LLC, VeraSun Granite City, LLC, VeraSun Reynolds, LLC, VeraSun Biodiesel, LLC, Lehman Brothers Inc., Morgan Stanley & Co. Incorporated and UBS Securities LLC (incorporated by reference to Exhibit 4.3 to VeraSun Energy Corporation’s current report on Form 8-K filed on May 17, 2007).
4.9	Registration Rights Agreement, dated as of August 17, 2007, among VeraSun Energy Corporation and the Holders of Registrable Securities named therein.
10.1	Credit Agreement, dated February 6, 2006, by and among ASA OpCo Holdings, LLC, ASA Albion, LLC, ASA Bloomingburg, LLC, ASA Linden, LLC, WestLB AG, New York Branch, as Administrative Agent and the Lenders named therein (incorporated by reference to Exhibit 4.2 to ASAlliances Biofuels, LLC’s Registration Statement on Form S-1, file number 333-137356, filed on September 15, 2006).
10.2	First Amendment to Credit Agreement, dated May 23, 2006, by and among ASA OpCo Holdings, LLC, ASA Albion, LLC, ASA Bloomingburg, LLC, ASA Linden, LLC, WestLB AG, New York Branch, as Administrative Agent, and the Lenders named therein.
10.3	Second Amendment to Credit Agreement, dated August 15, 2006, by and among ASA OpCo Holdings, LLC, ASA Albion, LLC, ASA Bloomingburg, LLC, ASA Linden, LLC, WestLB AG, New York Branch, as Administrative Agent, the Lenders therein, and First National Bank of Omaha, as Collateral Agent.
10.4	Third Amendment to Credit Agreement and First Amendment to ASA Holdings Pledge Agreement, dated August 30, 2006, by and among ASA OpCo Holdings, LLC, ASA Albion, LLC, ASA Bloomingburg, LLC, ASA Linden, LLC, ASA Holdings, as Borrowers’ Agent, ASAlliances Biofuels, LLC, WestLB AG, New York Branch, as Administrative Agent, the Lenders therein, and First National Bank of Omaha, as Collateral Agent and Accounts Bank.
10.5	Omnibus Agreement (Consent, Fourth Amendment and Second Waiver), dated November 30, 2006, by and among ASA OpCo Holdings, LLC, ASA Albion, LLC, ASA Bloomingburg, LLC, ASA Linden, LLC, WestLB AG, New York Branch, as Administrative Agent, and the Lenders therein.
10.6	Second Omnibus Agreement (Second Consent, Fifth Amendment and Third Waiver), dated December 22, 2006, by and among ASA OpCo Holdings, LLC, ASA Albion, LLC, ASA Bloomingburg, LLC, ASA Linden, LLC, WestLB AG, New York Branch, as Administrative Agent, the Lenders therein, and First National Bank of Omaha, as Collateral Agent and Accounts Bank.
10.7	Third Omnibus Agreement (Sixth Amendment and Consent), dated July 21, 2007, by and among ASA OpCo Holdings, LLC, ASA Albion, LLC, ASA Bloomingburg, LLC, ASA Linden, LLC, WestLB AG, New York Branch, as Administrative Agent, and the Lenders named therein.

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31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Incorporated by reference to VeraSun Energy Corporation’s Registration Statement on Form S-1, as amended (file number 333-132861).

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SIGNATURE

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

	VeraSun Energy Corporation
Date: November 14, 2007	By:	/s/ Donald L. Endres
		Donald L. Endres
		Chief Executive Officer
	By:	/s/ Danny C. Herron
		Danny C. Herron
		Chief Financial Officer
		(principal accounting officer)

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