e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 2007


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

For the transition period from to

Commission File No. 1-32913

VeraSun Energy Corporation

(Exact name of registrant as specified in its charter)


South Dakota (State or other jurisdiction of incorporation or organization)		20-3430241 (IRS Employer Identification Number)

100 22nd Avenue Brookings, SD (Address of principal executive offices)		57006 (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 þ No o

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 o Accelerated filer o Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

The number of shares of Common Stock outstanding on April 27, 2007 was 76,899,555.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VERASUN ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31, 2007
	(Unaudited)		December 31, 2006
	(dollars in thousands)

Assets
Current Assets
Cash and cash equivalents	$	287,834	$	318,049
Receivables		56,143		62,549
Inventories		46,619		39,049
Prepaid expenses		5,217		4,187
Derivative financial instruments		3,330		12,382

Total current assets		399,143		436,216


Other Assets
Restricted cash held in escrow		25,183		44,267
Debt issuance costs, net		5,447		5,685
Goodwill		6,129		6,129
Deposits		530		480

		37,289		56,561


Property and Equipment, net		380,918		301,720

	$	817,350	$	794,497


Liabilities and Shareholders’ Equity
Current Liabilities
Current portion of deferred revenues	$	95	$	96
Accounts payable		45,991		36,391
Accrued expenses		10,157		2,961
Derivative financial instruments		7,650		11,331
Deferred income taxes		2,140		1,370

Total current liabilities		66,033		52,149


Long-Term Liabilities
Long-term debt		208,952		208,905
Deferred revenues, less current portion		1,590		1,613
Deferred income taxes		25,399		25,399

		235,941		235,917


Commitments and Contingencies

Shareholders’ Equity
Preferred stock, $0.01 par value; authorized 25,000,000 shares; none issued or outstanding		—		—
Common stock, $0.01 par value; authorized 250,000,000 shares; 76,611,643 and 75,463,640 shares issued and outstanding as of March 31, 2007 and December 31, 2006, respectively		766		755
Additional paid-in capital		425,333		417,049
Retained earnings		89,277		89,589
Accumulated other comprehensive loss		—		(962	)

		515,376		506,431

	$	817,350	$	794,497

See Notes to Condensed Consolidated Financial Statements.

VERASUN ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Three Months Ended March 31,
	2007			2006
	(dollars in thousands)
Cash Flows from Operating Activities
Net income (loss)	$	(312	)	$	2,735
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		2,534			2,364
Amortization of debt issuance costs and debt discount		285			307
Accretion of deferred revenue		(24	)		(24	)
Change in fair value of convertible put warrant		—			10,938
Change in derivative financial instruments		6,851			(4,491	)
Deferred income taxes		252			8,215
Loss on disposal of equipment		(82	)		—
Stock-based compensation expense		1,469			548
Excess tax benefits from share-based payment arrangements		(2,908	)		—
Changes in current assets and liabilities:
(Increase) decrease in:
Receivables		6,406			(1,597	)
Inventories		(7,570	)		(1,353	)
Prepaid expenses		(1,030	)		1,643
Increase (decrease) in:
Accounts payable		6,698			(6,895	)
Accrued expenses		7,196			5,011

Net cash provided by operating activities		19,765			17,401


Cash Flows from Investing Activities
Purchases of property and equipment		(56,757	)		(2,383	)
Payment of deposits		(50	)		—
Proceeds from sale of equipment		1			—

Net cash used in investing activities		(56,806	)		(2,383	)


Cash Flows from Financing Activities
Proceeds from the issuance of common stock		3,923			73
Excess tax benefits from share-based payment arrangements		2,908			—
Costs of raising capital		(5	)		—
Deferred offering costs paid		—			(411	)
Debt issuance costs paid		—			(1,088	)

Net cash provided by (used in) financing activities		6,826			(1,426	)

Net increase (decrease) in cash and cash equivalents		(30,215	)		13,592

Cash and Cash Equivalents
Beginning		318,049			29,714

Ending	$	287,834		$	43,306

See Notes to Condensed Consolidated Financial Statements.

VERASUN ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(dollars in thousands, except per share data)

Note 1. Basis of Presentation

The accompanying condensed consolidated balance sheet as of December 31, 2006, which has been derived from audited consolidated financial statements, and the unaudited interim condensed consolidated financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and include the accounts of VeraSun Energy Corporation (“VEC”) and its wholly owned subsidiaries, VeraSun Aurora Corporation (“VAC”), VeraSun Fort Dodge, LLC (“VFD”), VeraSun Charles City, LLC (“VCC”), VeraSun Welcome, LLC (“VSW”), VeraSun Marketing, LLC (“VSM”), VeraSun Hartley, LLC (“VSH”), VeraSun Granite City (“VGC”), and VeraSun Reynolds (“VRL”). VEC and its subsidiaries are collectively referred to as the “Company.” All material intercompany accounts and transactions have been eliminated in consolidation. 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 have been condensed or omitted pursuant to those rules and regulations, 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 audited consolidated financial statements and notes thereto for the year ended December 31, 2006 included in the Company’s Form 10-K (Registration No. 1-32913) filed with the SEC on March 29, 2007.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation of the consolidated financial position, results of operations and cash flows for the periods presented.

Management is required to make certain estimates and assumptions which affect the amount of assets, liabilities, revenues and expenses the Company has reported and its disclosure of contingent assets and liabilities as of the date of the consolidated financial statements. The results of the interim periods are not necessarily indicative of the results for the full year.

Recently issued accounting standard: The Company adopted the provisions of FASB Interpretation 48, Accounting for Uncertainty in Income Taxes, on January 1, 2007. Previously, the Company had accounted for tax contingencies in accordance with Statement of Financial Accounting Standards 5, Accounting for Contingencies. As required by Interpretation 48, which clarifies Statement 109, Accounting for Income Taxes, the Company recognizes 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 the more-likely-than-not threshold, 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, the Company applied Interpretation 48 to all tax positions for which the statute of limitations remained open. As a result of the implementation of Interpretation 48, no material adjustment was recognized in the liability for unrecognized income tax benefits.

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

The Company is 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, the Company is no longer subject to U.S. federal, state or local income tax examinations by tax authorities for the years before 2003.

The Company is currently under examination by the Internal Revenue Service for tax year 2004. The Company expects that examination to be concluded and settled in the next 12 months. The Company has not recorded any material adjustment in the liability for unrecognized income tax benefits related to this audit.

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

Note 2. Inventories

A summary of inventories is as follows:


	March 31,		December 31,
	2007		2006
Corn	$	31,259	$	24,492
Supplies		8,081		7,084
Chemicals		1,390		1,214
Work in process		2,508		2,489
Distillers grains		449		431
Ethanol		2,932		3,339

	$	46,619	$	39,049

Note 3. Earnings (Loss) Per Common Share

Basic earnings (loss) per common share (“EPS”) is computed by dividing net income (loss) 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, unless the effect is antidilutive.

VERASUN ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) — Continued
(dollars in thousands, except per share data)

A reconciliation of net income (loss) and common stock share amounts used in the calculation of basic and diluted EPS for the three months ended March 31, 2007 and 2006 follows:


				Weighted
				Average
	Net			Shares		Per Share
	Income (Loss)			Outstanding		Amount
2007:
Basic EPS	$	(312	)		75,708,911	$	—
Effects of dilutive securities:
Stock options, restricted stock and warrants — antidilutive		—			—		—

Diluted EPS	$	(312	)		75,708,911	$	—


2006:
Basic EPS	$	2,735			62,413,302	$	0.04
Effects of dilutive securities:
Stock options, restricted stock and warrants		—			2,786,781		—

Diluted EPS	$	2,735			65,200,083	$	0.04

Stock options, restricted stock and warrants for 6,667,888 shares for the three months ended March 31, 2007, were not included in the calculation of diluted EPS as their effects would be antidilutive. Warrants outstanding for 1,475,681 shares of common stock at an exercise price of $0.52 per share and performance-based stock option awards of 620,041 at a weighted average exercise price of $2.08 per share were not included in the computation of diluted EPS for the three months ended March 31, 2006 because the related performance conditions or the accounting grant date had not yet been met.

Note 4. Stock-Based Compensation and Other Share-Based Awards

Compensation expense charged against income for grants under the Company’s stock incentive plan (“Plan”), was $1,469 and $548 for the three months ended March 31, 2007 and 2006, respectively. The total income tax benefit recognized in the consolidated statement of operations for grants under the Plan was $401 and $192 for the three months ended March 31, 2007 and 2006, respectively.

Cash received from the exercise of options and awards under the Plan was $1,342 and $73 for the three months ended March 31, 2007 and 2006, respectively. The Company recognized an excess tax benefit of $2,908 and $0 for the three months ended March 31, 2007 and 2006, respectively, in connection with exercises.

The Company applies Financial Accounting Standards Board (“FASB”) Statement No. 123 (revised), Share-Based Payment (“Statement No. 123R”), utilizing the modified prospective application method. Under the modified prospective approach, Statement No. 123R applies to new awards and to awards that were outstanding as of January 1, 2006 that are subsequently modified, repurchased or cancelled. Compensation expense includes compensation expense for awards granted under the Plan prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of FASB Statement No. 123, and includes compensation expense for awards granted under the Plan subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of Statement No. 123R.

Service-Based Awards

Service-based option awards (“Service Awards”) under the Plan are generally granted with an exercise price equal to the market price of the Company’s common stock at the date of grant. These awards generally vest based on five years of continuous service and have ten year contractual terms. These awards can only be exercised if the holder of the award is still employed or in the service of the Company at the time of exercise and for a specified period after termination of employment. Certain Service Awards granted under the Plan provide for accelerated vesting if there is a change in control as defined in the Plan.

The fair value of each Service Award is estimated on the date of grant using the Black-Scholes single option pricing model with the assumptions described below for the periods presented. Expected volatility is based on the stock volatility for a comparable publicly traded company for the period prior to the Company’s initial public offering (“IPO”) date in June 2006 and is based on the Company’s stock activity from the IPO date to March 31, 2007, considered collectively for the expected term of the award. The Company uses historical activity to estimate option exercise, forfeiture and employee termination assumptions within the valuation model. The expected term of options granted is generally derived using the mid-point between the

VERASUN ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) — Continued
(dollars in thousands, except per share data)

date options become exercisable (generally five years) and the date at which they expire (generally ten years). The risk-free interest rate for periods within the contractual life of the Service Award is based on the United States Treasury yield curve in effect at the time of grant.


		Three Months Ended March 31,
		2007				2006
Expected volatility			59	%			58	%
Expected dividend yield	None				None
Expected term	8 - 10 years				8 - 10 years
Risk-free interest rate			4.6-4.9	%			4.8-4.9	%

The following table lists Service Award activity under the Plan for the three months ended March 31, 2007:


				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
Options	Shares			Price		Term		Value
Outstanding at January 1, 2007		4,033,205		$	9.33
Granted		53,289			16.87
Forfeited		(112,637	)		23.00
Exercised		(509,126	)		2.00

Outstanding at March 31, 2007		3,464,731		$	10.08		8.0	$	37,978

Vested or expected to vest as of March 31, 2007		3,378,496		$	9.78		8.0	$	37,893

Exercisable at March 31, 2007		2,074,862		$	2.27		7.3	$	36,571

The Company applied a forfeiture rate of 3% when calculating the amount of options expected to vest as of March 31, 2007. The weighted average grant date fair value of options granted during the three months ended March 31, 2007 and 2006 was $11.86 and $3.70 per share, respectively. The total intrinsic value of options exercised during the three months ended March 31, 2007 and 2006 was $8,060 and $626, respectively.

Restricted stock awards (“Restricted Stock”) under the Plan generally vest over a period of five years. If the holder of Restricted Stock is no longer employed or in the service of the Company, nonvested shares are automatically forfeited. Certain Restricted Stock awards granted under the Plan provide for accelerated vesting if there is a change in control as defined in the Plan.

The following table shows the status of the Company’s nonvested Restricted Stock as of March 31, 2007 and changes during the three months ended March 31, 2007:


				Weighted
				Average
				Grant Date
Restricted Stock	Shares			Fair Value
Nonvested at January 1, 2007		340,896		$	22.69
Granted		6,089			17.82
Forfeited		(37,546	)		23.00
Vested		—			—

Nonvested at March 31, 2007		309,439		$	22.56

As of March 31, 2007, there was $22,998 of total unrecognized compensation expense related to nonvested Service Awards and Restricted Stock granted under the Plan. This expense is expected to be recognized over a weighted average period of 2.5 years. The total fair value of shares vested during the three months ended March 31, 2007 and 2006 was $0 and $191, respectively. The grant date fair value of nonvested Restricted Stock was determined using the value of the Company’s common stock sold on or near the date of grant.

VERASUN ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) — Continued
(dollars in thousands, except per share data)

Performance-Based Awards

Prior to the Company’s IPO, performance-based option awards (“Performance Awards”) under the Plan were generally awarded at the January meeting of the Company’s Board of Directors. The vesting of Performance Awards was contingent upon meeting various individual, departmental and company-wide goals. Performance Awards were generally granted with an exercise price equal to the market price of the Company’s common stock at the date of grant and have ten year contractual terms. These awards can only be exercised if the holder of the award is still employed or in the service of the Company at the time of exercise, and for a specified period after termination of employment.

The fair value of each Performance Award was estimated at the date of grant using the same option valuation model used for Service Awards granted under the Plan and assumed that performance goals would be achieved at a rate of 97%. If such goals were not met, or were met at a rate less than 97%, compensation expense was adjusted to the appropriate amount to be recognized and any recognized compensation expense above that amount was reversed. The inputs for expected volatility, expected dividend yield and risk-free interest rate used in estimating the fair value of Performance Awards were the same as those noted in the table described for Service Awards.

The following table lists Performance Award activity under the Plan for the three months ended March 31, 2007:


						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
Options	Shares			Price		Term		Value
Outstanding at January 1, 2007		1,258,297		$	1.64
Granted		—			—
Forfeited		—			—
Exercised		(205,093	)		1.04

Outstanding at March 31, 2007		1,053,204		$	1.75		7.1	$	19,081

Vested or expected to vest as of March 31, 2007		1,053,204		$	1.75		7.1	$	19,081

Exercisable at March 31, 2007		1,053,204		$	1.75		7.1	$	19,081

The weighted average grant date fair value of Performance Awards granted was $4.65 per share for the three months ended March 31, 2006 . The aggregate intrinsic value of Performance Awards exercised during the three months ended March 31, 2007 and 2006 was $3,434 and $161, respectively. As of March 31, 2007, there was no unrecognized compensation expense related to Performance Awards because all outstanding Performance Awards vested upon completion of the IPO.

Other Share-Based Awards

Service-Based Awards: In connection with its service agreement with a third party financial advisor (“Advisor”), the Company granted a warrant to the Advisor to purchase 96,376 shares of common stock. The warrant was fully vested at December 27, 2002. The warrant has an exercise price of $0.52 per share and expires February 25, 2008. The warrant is not transferable, except to officers of the Advisor. The aggregate intrinsic value of this warrant as of March 31, 2007 was $1,243. A total of 32,149 shares had been issued under the warrant through March 31, 2007.

The Company granted warrants to certain employees in 2002 to purchase 578,258 shares of common stock which vest over a five year period. As of March 31, 2007, warrants for 277,652 shares have been exercised and warrants for an additional 208,081 shares were exercisable. The warrants have an exercise price of $0.52 per share and expire on the earliest of August 20, 2007, or the day of termination of the warrant holder’s employment with the Company for cause, or the day of voluntary termination of the warrant holder’s employment. Compensation expense of $5 and $0 was recognized by the Company during the three months ended March 31, 2007 and 2006, respectively, in connection with the grant of these warrants. As of March 31, 2007, there was $4 of unrecognized compensation expense related to these warrants and the aggregate intrinsic value of the outstanding amounts was $4,026.

Performance- and Market-Based Awards: In 2002, the Company granted “claw back” warrants to purchase 1,475,681 shares of common stock to certain investors of the Company. The warrants were fully exercisable as of March 31, 2007 at an exercise price of $0.52 per share and expire on June 14, 2016. None of the warrants have been exercised. The aggregate intrinsic value of these warrants as of March 31, 2007 was $28,554.

The Company issues new shares upon the exercise of options and warrants.

VERASUN ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) — Continued
(dollars in thousands, except per share data)

Note 5. Comprehensive Income

Comprehensive income was $650 and $2,126 for the three months ended March 31, 2007 and 2006, respectively. The difference between comprehensive income and net income (loss) shown in the statements of operations is attributed solely to the change in unrealized gains and losses on hedging activities during the periods presented.

Note 6. Condensed Segment Information

The Company’s reportable segments are distinguished by those business units that manufacture and sell ethanol and its co-products and business units that are engaged in other activities. The “Ethanol Production” segment includes the operations of VAC, VFD, VCC, VSW, VSH, VGC and VRL. The Company’s remaining operations are aggregated and classified as “All Other”. Companies combined as “All Other” function primarily for the purpose of research, providing management services or marketing of E85. Cash balances are primarily reported in segment assets for the “All Other” category. A summary of segment information as of and for the three months ended March 31, 2007 and 2006 is as follows:


	2007
	Ethanol		All
	Production		Other			Totals

Revenue from external customers	$	125,177	$	18,684		$	143,861
Intersegment revenue		17,508		—			17,508
Segment profit (loss) — EBITDA		9,620		(5,829	)		3,791
Segment assets		451,752		365,598			817,350


	2006
	Ethanol		All
	Production		Other		Totals

Revenue from external customers	$	109,227	$	654	$	109,881
Segment profit — EBITDA		29,321		289		29,610
Segment assets		236,620		176,841		413,461

The following schedule is presented to reconcile EBITDA to income (loss) before income taxes:


	2007			2006
Segment profit — EBITDA	$	3,791		$	29,610
Depreciation		(2,534	)		(2,364	)
Interest expense*		(1,752	)		(16,296	)

Income (loss) before income taxes		(495	)		10,950


*		Amortization of debt issuance costs and debt discount are included in interest expense.

Note 7. Guarantors / Non-Guarantors Condensed Consolidating Financial Statements

In accordance with the indenture governing the Company’s senior secured 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 VEC (the issuer of the notes), subsidiaries that are guarantors of the notes and subsidiaries that are non-guarantors of the notes. VAC, VFD, VCC, VSW, VSH, VGC, VRL, and VSM, each 100% wholly-owned subsidiaries of VEC, are combined as guarantors.

VERASUN ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) — Continued
(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING BALANCE SHEET
MARCH 31, 2007

ASSETS


	Issuer (VEC)		Guarantors		Non-Guarantors		Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	306,548	$	—	$	—	$	(18,714	)	$	287,834
Receivables		16,555		49,051		40		(9,503	)		56,143
Inventories		—		46,619		—		—			46,619
Prepaid expenses		390		4,827		—		—			5,217
Derivative financial instruments		—		3,330							3,330

Total current assets		323,493		103,827		40		(28,217	)		399,143


Other Assets
Restricted cash held in escrow		25,183		—		—		—			25,183
Investment in subsidiaries		174,961		—		—		(174,961	)		—
Debt issuance costs, net		5,447		—		—		—			5,447
Deposits		330		200		—		—			530
Intercompany notes receivable		226,041		30,613		—		(256,654	)		—
Goodwill		6,129		—		—		—			6,129
Deferred income taxes		5,716		—		365		(6,081	)		—

		443,807		30,813		365		(437,696	)		37,289


Property and Equipment, net		1,664		375,346		3,908		—			380,918

	$	768,964	$	509,986	$	4,313	$	(465,913	)	$	817,350

VERASUN ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) — Continued
(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING BALANCE SHEET — Continued
MARCH 31, 2007

LIABILITIES AND SHAREHOLDERS’ AND MEMBERS’ EQUITY (DEFICIT)


	Issuer (VEC)		Guarantors		Non-Guarantors			Eliminations			Consolidated
Current Liabilities
Outstanding checks in excess of bank balance	$	—	$	18,694	$	20		$	(18,714	)	$	—
Current maturities of long-term debt		—		169,846		2,416			(172,262	)		—
Current portion of deferred revenue		—		95		—			—			95
Accounts payable		5,752		43,669		48			(3,478	)		45,991
Accrued expenses		7,936		8,285		97			(6,161	)		10,157
Derivative financial instruments		—		7,650		—			—			7,650
Deferred income taxes		335		1,805								2,140

Total current liabilities		14,023		250,044		2,581			(200,615	)		66,033


Long-Term Liabilities
Long-term debt, less current maturities		239,565		51,221		2,422			(84,256	)		208,952
Deferred revenue, less current portion		—		1,590		—			—			1,590
Deferred income taxes		—		31,480		—			(6,081	)		25,399

		239,565		84,291		2,422			(90,337	)		235,941


Shareholders’ and Members’ Equity (Deficit)
Preferred stock		—		—		—			—			—
Common stock		766		—		—			—			766
Additional paid-in capital		425,333		25,263		—			(25,263	)		425,333
Retained earnings		89,277		89,135		—			(89,135	)		89,277
Members’ equity (deficit)		—		61,253		(690	)		(60,563	)		—

		515,376		175,651		(690	)		(174,961	)		515,376

	$	768,964	$	509,986	$	4,313		$	(465,913	)	$	817,350

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 March 31, 2007


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated

Revenues	$	886		$	162,018		$	—		$	(18,394	)	$	144,510
Cost of goods sold		10			152,817			—			(17,561	)		135,266

Gross profit		876			9,201			—			(833	)		9,244
Selling, general and administrative expenses		8,851			3,322			247			(886	)		11,534

Operating income (loss)		(7,975	)		5,879			(247	)		53			(2,290	)


Other income (expense):
Interest expense		(5,837	)		(1,314	)		(23	)		5,422			(1,752	)
Interest income		8,598			369			—			(5,422	)		3,545
Equity in earnings of subsidiaries		2,993			—			—			(2,993	)		—
Other		—			2			—			—			2

		5,754			(943	)		(23	)		(2,993	)		1,795

Income (loss) before income taxes		(2,221	)		4,936			(270	)		(2,940	)		(495	)
Income tax expense (benefit)		(1,909	)		1,826			(100	)		—			(183	)

Net income (loss)	$	(312	)	$	3,110		$	(170	)	$	(2,940	)	$	(312	)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Three months Ended March 31, 2007


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated

Net cash provided by (used in) operating activities	$	(42,973	)	$	198		$	182		$	62,358		$	19,765


Cash Flows from Investing Activities
Purchases of property and equipment with restricted cash held in escrow		19,084			(19,084	)		—			—			—
Purchases of property and equipment		(485	)		(56,068	)		(204	)		—			(56,757	)
Payment of deposits		(50	)		—			—			—			(50	)
Proceeds from sale of property and equipment		—			1			—			—			1

Net cash provided by (used in) investing activities		18,549			(75,151	)		(204	)		—			(56,806	)


Cash Flows from Financing Activities
Outstanding checks in excess of bank balance		—			12,595			20			(12,615	)		—
Principal payments on long-term debt		—			62,358			—			(62,358	)		—
Proceeds from issuance of common stock		3,923			—			—			—			3,923
Excess tax benefits from share-based payment arrangements		2,908			—			—			—			2,908
Costs of raising capital		(5	)		—			—			—			(5	)

Net cash provided by financing activities		6,826			74,953			20			(74,973	)		6,826

Net decrease in cash and cash equivalents		(17,598	)		—			(2	)		(12,615	)		(30,215	)

Cash and cash equivalents, beginning of period		324,146			—			2			(6,099	)		318,049

Cash and cash equivalents, end of period	$	306,548		$	—		$	—		$	(18,714	)	$	287,834

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 (VEC)		Guarantors		Non-Guarantors			Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	324,146	$	—	$	2		$	(6,099	)	$	318,049
Receivables		4,326		64,503		(60	)		(6,220	)		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		119,725		(58	)		(12,373	)		436,216


Other Assets
Restricted cash held in escrow		44,267		—		—			—			44,267
Debt issuance costs, net		5,685		—		—			—			5,685
Goodwill		6,129		—		—			—			6,129
Investment in subsidiaries		171,005		—		—			(171,005	)		—
Deposits		280		200		—			—			480
Intercompany notes receivable		168,385		13,374		—			(181,759	)		—
Deferred income taxes		5,716		—		365			(6,081	)		—

		401,467		13,574		365			(358,845	)		56,561


Property and Equipment, net		642		297,373		3,705			—			301,720

	$	731,031	$	430,672	$	4,012		$	(371,218	)	$	794,497

VERASUN ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) — Continued
(dollars in thousands, except per share data)

CONDENSED CONSOLIDATED BALANCE SHEET — Continued
December 31, 2006

LIABILITIES AND SHAREHOLDERS’ AND MEMBERS’ EQUITY (DEFICIT)


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated
Current Liabilities
Outstanding checks in excess of bank balance	$	—		$	6,099		$	—		$	(6,099	)	$	—
Current maturities of long-term debt		—			108,430			2,089			(110,519	)		—
Current portion of deferred revenue		—			96			—			—			96
Accounts payable		848			40,668			14			(5,139	)		36,391
Accrued expenses		1,389			2,614			40			(1,082	)		2,961
Derivative financial instruments		—			11,331			—			—			11,331
Deferred income taxes		83			1,287			—			—			1,370

Total current liabilities		2,320			170,525			2,143			(122,839	)		52,149


Long-Term Liabilities
Long-term debt, less current maturities		222,280			55,475			2,389			(71,239	)		208,905
Deferred revenue, less current portion		—			1,613			—			—			1,613
Deferred income taxes		—			31,480			—			(6,081	)		25,399

		222,280			88,568			2,389			(77,320	)		235,917


Shareholders’ and Members’ Equity (Deficit)
Preferred stock		—			—			—			—			—
Common stock		755			—			—			—			755
Additional paid-in capital		417,049			25,263			—			(25,263	)		417,049
Retained earnings		89,589			85,127			—			(85,127	)		89,589
Members’ equity (deficit)		—			62,151			(520	)		(61,631	)		—
Accumulated other comprehensive loss		(962	)		(962	)		—			962			(962	)

		506,431			171,579			(520	)		(171,059	)		506,431

	$	731,031		$	430,672		$	4,012		$	(371,218	)	$	794,497

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 March 31, 2006


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated

Revenues	$	—		$	110,704		$	—		$	—		$	110,704
Cost of goods sold		—			81,358			—			—			81,358

Gross profit		—			29,346			—			—			29,346
Selling, general and administrative expenses		850			2,847			73			—			3,770

Operating income (loss)		(850	)		26,499			(73	)		—			25,576


Other income (expense):
Interest expense, including change in fair value of convertible put warrant		(16,748	)		(3,653	)		(40	)		4,145			(16,296	)
Interest income		5,470			343			—			(4,145	)		1,668
Equity in earnings of subsidiaries		14,525			—			—			(14,525	)		—
Other		—			2			—			—			2

		3,247			(3,308	)		(40	)		(14,525	)		(14,626	)

Income (loss) before income taxes		2,397			23,191			(113	)		(14,525	)		10,950
Income tax expense (benefit)		(338	)		8,595			(42	)		—			8,215

Net income (loss)	$	2,735		$	14,596		$	(71	)	$	(14,525	)	$	2,735

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Three months Ended March 31, 2006


	Issuer (VEC)			Guarantors			Non-Guarantors			Eliminations			Consolidated

Net cash provided by (used in) operating activities	$	(1,270	)	$	19,429		$	(758	)	$	—		$	17,401


Cash Flows from Investing Activities
Intercompany loan		6,140			(9,834	)		—			3,694			—
Purchases of property and equipment		(75	)		(11,182	)		(167	)		9,041			(2,383	)

Net cash provided by (used in) investing activities		6,065			(21,016	)		(167	)		12,735			(2,383	)


Cash Flows from Financing Activities
Outstanding checks in excess of bank balance		—			(414	)		—			414			—
Proceeds from long-term debt		9,809			2,001			925			(12,735	)		—
Proceeds from issuance of common stock		73			—			—			—			73
Deferred offering costs paid		(411	)		—			—			—			(411	)
Debt issuance costs paid		(1,088	)		—			—			—			(1,088	)

Net cash provided by(used in) financing activities		8,383			1,587			925			(12,321	)		(1,426	)

Net increase in cash and cash equivalents		13,178			—			—			414			13,592

Cash and cash equivalents, beginning of period		32,905			—			—			(3,191	)		29,714

Cash and cash equivalents, end of period	$	46,083		$	—		$	—		$	(2,777	)	$	43,306

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 (Registration No. 1-32913) filed with the SEC on March 29, 2007 (“Form 10-K”). VeraSun Energy Corporation and its subsidiaries are collectively referred to as the “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 involve risks and uncertainties. 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, possible 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.

These forward-looking statements, and others we make from time to time, are subject to a number of 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. 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 Energy Corporation 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 primarily of ethanol, may become increasingly important over time as an alternative to unleaded gasoline.

We own and operate three of the largest ethanol production facilities in the U.S., with a combined ethanol production capacity of 340 million gallons per year, or “MMGY”. As of April 16, 2007, our ethanol production capacity represented approximately 6% of the total ethanol production capacity in the U.S., according to the RFA. We expect to operate five facilities with an aggregate production capacity of 560 MMGY by the end of the first quarter of 2008 and six facilities with an aggregate production capacity of 670 MMGY by the end of 2008. See Note 6 to the Condensed Consolidated Financial Statements under Item 1 of Part I of this report for information concerning our business segments.

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.

Our facility in Aurora, South Dakota commenced operations in December 2003 and our facility in Fort Dodge, Iowa commenced operations in October 2005. We commenced startup operations at our facility in Charles City, Iowa in April 2007. Construction of our facilities in Hartley, Iowa, and Welcome, Minnesota commenced in late 2006, and we expect those facilities to begin production by the end of the first quarter of 2008. We also broke ground for a facility in Reynolds, Indiana in April 2007 and expect to begin operations there by the end of 2008.

Executive Summary

Highlights for the three months ended March 31, 2007, are as follows:

	•		Total revenues increased 30.5% or $33.8 million compared to the 2006 comparable period.

	•		Cash flows provided by operating activities were $19.8 million.

	•		Net loss was $312,000 for the 2007 period, compared to net income of $2.74 million for the 2006 period.

	•		Ethanol shipped was 59.2 million gallons, an increase of 4.7 million gallons or 8.7% higher than the 2006 period.

	•		Production volume was 59.4 million gallons, up 5.5 million gallons or 10.2% compared to the 2006 period.

	•		There were no earnings per share for the 2007 period compared to the fully diluted earnings per share of $0.04 for the 2006 period.

Components of Revenues and Expenses

Total revenues. Our primary source of revenue is the sale of ethanol produced at our Aurora, Fort Dodge and Charles City 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^tm fuel.

The selling prices we realize 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 expense. 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 in May and June and tends to decrease during the fall harvest in October and November. 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.

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. We expect selling, general and administrative expenses to increase significantly in connection with our expansion plans, which will require us to hire more personnel at our additional facilities. We also anticipate continuing higher expenses as a public company as a result of additional legal and corporate governance expenses, including: costs associated with compliance with Section 404 of the Sarbanes-Oxley Act of 2002; salary and payroll-related costs for additional accounting staff; and listing and transfer agent fees.

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, debt extinguishment costs 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 expected issuance of additional debt in the second quarter of 2007.

Result of Operations

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


	Three Months Ended March 31,
	2007						2006
	(unaudited)						(unaudited)
				(dollars in thousands)
Total revenues	$	144,510			100.0	%	$	110,704		100.0	%
Cost of goods sold		135,266			93.6			81,358		73.5

Gross profit		9,244			6.4			29,346		26.5
Selling, general and administrative expenses		11,534			8.0			3,770		3.4

Operating income		(2,290	)		(1.6	)		25,576		23.1
Other income (expense), net		1,795			1.2			(14,626	)	(13.2	)


Income before income taxes		(495	)		(0.4	)		10,950		9.9
Income tax expense (benefit)		(183	)		(0.1	)		8,215		7.4

Net income (loss)	$	(312	)		(0.3	)%	$	2,735		2.5	%

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


	Three Months Ended March 31,
	2007		2006
	(unaudited)		(unaudited)

Operating data:
Ethanol sold (gallons) (1)		59,249,075		54,506,270
Average gross price of ethanol sold (dollars per gallon)	$	2.13	$	1.77

Average corn cost per bushel		4.05		1.87
Average natural gas cost per MMBTU		8.21		9.69
Average dry distillers grains price per ton		89		87

Other financial data:
EBITDA (2)	$	3,791	$	29,610
Net cash provided by operating activities		19,765		17,401


(1)		Excludes ethanol sold in VE85™ sales.

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

Non-GAAP Financial Measures

Our MD&A includes financial information prepared in accordance with accounting principles generally accepted in the U.S., or GAAP, as well as another financial measure, EBITDA, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of EBITDA information is intended to supplement investor’s understanding of our operating performance and liquidity. Furthermore, this measure is not intended to replace 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.

We believe that 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 for reasons unrelated to overall operating performance. EBITDA has its limitations as an analytical tool, and you should not consider it in isolation or as a substitute for analysis of our financial results as reported under GAAP. 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.

Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to us to service our debt or to invest in the growth of our business. 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 (loss) for the periods presented (dollars in thousands):


	Three Months Ended March 31,
	2007			2006
	(unaudited)			(unaudited)

Net income (loss)	$	(312	)	$	2,735
Depreciation		2,534			2,364
Interest expense		1,752			16,296
Income tax expense (benefit)		(183	)		8,215

EBITDA	$	3,791		$	29,610

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006

Total revenues. Total revenues, which includes revenue from the sale of ethanol, distillers grains and VE85(TM), increased by $33.8 million, or 30.5%, to $144.5 million for the three months ended March 31, 2007 from $110.7 million for the three months ended March 31, 2006. The increase in total revenues was primarily the result of an 8.7% increase in ethanol volume sold and an increase in average ethanol prices of $0.36 per gallon, or 20.3%, compared to the three months ended March 31, 2006. Ethanol production increased by 5.5 million gallons, or 10.2%, as a result of increased operating efficiencies.

Net sales from ethanol increased $29.8 million, or 31.2%, to $125.5 million for the three months ended March 31, 2007 from $95.7 million for the three months ended March 31, 2006. The average price of ethanol sold was $2.13 per gallon for the three months ended March 31, 2007, compared to $1.77 per gallon for the three months ended March 31, 2006.

There was no net gain or loss from derivatives included in net sales for the three months ended March 31, 2007, compared to a net gain of $492,000 for the three months ended March 31, 2006.

Net sales from co-products increased $2.9 million, or 21.7%, to $16.4 million for the three months ended March 31, 2007 from $13.5 million for the three months ended March 31, 2006. Co-product sales increased due to an increase in the average price per ton in the 2007 period.

Net sales of VE85(TM), our branded E85 product, increased $1.2 million to $1.9 million for the three months ended March 31, 2007 from $718,000 for the three months ended March 31, 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 $20.1 million to $9.2 million for the three months ended March 31, 2007 from $29.3 million for the three months ended March 31, 2006. The decrease in gross profit was primarily due to higher corn costs, partially offset by an increase in ethanol volume sold in the 2007 period as compared to the 2006 period. Comparisons for the full year 2007 are expected to be adversely affected by these relatively higher corn costs.

Corn costs increased $48.9 million to $84.6 million for the three months ended March 31, 2007 from $35.6 million for the three months ended March 31, 2006. Corn costs represented 62.5% of our cost of goods sold before taking into account our co-product sales and 50.4% of our cost of goods sold after taking into account co-product sales for the three months ended March 31, 2007, compared to 43.8% of our cost of goods sold before taking into account our co-product sales and 27.2% of our cost of goods sold after taking into account co-product sales for the three months ended March 31, 2006.

The increase in total corn costs in the 2007 period was primarily driven by an increase in cash corn prices versus the prior period. In addition, our 2007 corn costs included mark-to-market losses of $6.8 million for derivatives relating to future deliveries of corn. We had a mark-to-market gain of $5.8 million in the 2006 period, resulting in a $12.6 million increase in corn costs between the periods as a result of these mark-to-market adjustments. On March 30,2007 the USDA reported larger than expected corn planting intentions for the 2007 crop year, which we believe resulted in a decrease in CBOT corn futures prices on that date.

The net loss from derivatives included in cost of goods sold was $13.7 million for the three months ended March 31, 2007, compared to a net loss of $1.3 million for the three months ended March 31, 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 decreased $1.5 million to $14.6 million for the three months ended March 31, 2007 from $16.1 million for the three months ended March 31, 2006, and accounted for 10.8% of our cost of goods sold for the three months ended March 31, 2007, compared to 19.7% of our cost of goods sold for the three months ended March 31, 2006. The decrease in natural gas costs was primarily driven by a decrease in natural gas prices per MMBTU in the 2007 period.

Transportation expense increased $4.7 million or 38.8%, to $16.7 million for the three months ended March 31, 2007 from $12.1 million for the three months ended March 31, 2006, primarily due to the additional volume of ethanol and co-products shipped, along with increased rail rates in the 2007 period. Transportation expense accounted for 12.4% of our cost of goods sold for the three months ended March 31, 2007, compared to 14.8% of our cost of goods sold for the three months ended March 31, 2006.

Labor and manufacturing overhead costs increased $2.1 million to $8.7 million for the three months ended March 31, 2007 from $6.6 million for the three months ended March 31, 2006. The increase was primarily due to additional staffing needed to achieve higher production rates from our operating facilities.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $7.8 million to $11.5 million for the three months ended March 31, 2007 from $3.8 million for the three months ended March 31, 2006. The increase was primarily the result of increased management and administrative costs to support our growth and public company status, $1.2 million of pre-startup costs relating to our Charles City facility that began operations in April 2007, and costs of preparation for the Aventine marketing transition. Professional fees for auditing and advisory services relating to preparation for Section 404 of SOX exceeded $1.3 million in the 2007 period. We are required to be in compliance with SOX Section 404 as of December 31, 2007.

Other income (expense). Interest expense decreased $14.5 million to $1.8 million for the three months ended March 31, 2007, compared to $16.3 for the three months ended March 31, 2006. Interest expense in the 2006 period included a charge of $10.9 million relating to a warrant that was fully exercised in connection with our IPO.

Interest income increased $1.9 million to $3.5 million for the three months ended March 31, 2007, compared to $1.7 million for the three months ended March 31, 2006. The increase was primarily attributable to the interest on funds received from our IPO.

Income taxes. The income tax benefit was $183,000 for the three months ended March 31, 2007 versus an income tax expense of $8.2 million for the three months ended March 31, 2006. The effective tax rate for the three months ended March 31, 2007 was 37.0%, compared to 75.0% for the three months ended March 31, 2006. The decrease in effective tax rate was due to the 2006 period including non-deductible warrant charges of $10.9 million.

Liquidity and Capital Resources

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

As of March 31, 2007, we had $287.8 million of unrestricted cash and cash equivalents. We also had $25.2 million of cash remaining in escrow for the construction of the Charles City facility at March 31, 2007, which we expect to use in the second quarter of 2007.

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):


	Three Months Ended March 31,
	2007			2006
	(unaudited)			(unaudited)

Net cash provided by operating activities	$	19,765		$	17,401
Net cash used in investing activities		(56,806	)		(2,383	)
Net cash provided by (used in) financing activities		6,826			(1,426	)

Net increase (decrease) in cash and cash equivalents	$	(30,215	)	$	13,592

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 in our business for future growth.

Cash provided by operating activities was $19.8 million for the three months ended March 31, 2007, compared to $17.4 million provided by operating activities for the three months ended March 31, 2006. At March 31, 2007, we had total unrestricted cash and cash equivalents of $287.8 million compared to $43.3 million at March 31, 2006.

Cash used in investing activities was $56.8 million for the three months ended March 31, 2007 compared to cash used of $2.4 million for the three months ended March 31, 2006. The increase was primarily due to construction expenditures and the acquisitions of other fixed assets in the 2007 period. In addition, $20.2 million was spent from escrowed cash for the construction of our Charles City facility.

Cash provided by financing activities for the three months ended March 31, 2007 was $6.8 million, compared to $1.4 million used in financing activities for the three months ended March 31, 2006. The increase relates primarily to proceeds and tax benefits from issuance of stock upon exercise of options.

As of March 31, 2007, we had total debt of $210.0 million, before $1.0 million of unaccreted discount. In addition, we had total borrowing capacity of $30.0 million under our credit agreement. Letters of credit in an aggregate amount of $2.9 million have been issued and undrawn under our credit agreement, leaving $27.1 million of undrawn borrowing capacity at March 31, 2007.

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 agreement. We also expect to issue up to $450 million of long-term debt to finance a portion of capital expenditures in 2007 and 2008, as well as to fund other general corporate purposes.

In addition to the construction of our Charles City, Hartley, Welcome and Reynolds facilities, we may also 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. Our ability to access these sources of capital is restricted by the indenture governing our senior secured notes and the terms of our credit agreement.

We expect to make capital expenditures of approximately $440 million for the remainder of 2007. In 2007, we expect to spend between $450 million and $500 million primarily 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 three months ended March 31, 2007, we had spent $56.8 million for purchase of property and equipment, in addition to $20.2 million spent from escrowed cash for the construction of our Charles City facility.

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of financial statements requires the use of estimates and assumptions which are based upon management’s current judgment. The process used by management encompasses its knowledge and experience about past and current events and certain assumptions on future events. The judgments and estimates regard the effects of 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 the foregoing disclosures. In addition, there are other items within our consolidated financial statements that require estimation, but are not deemed critical, as defined above.

Revenue recognition. Revenue from the production of ethanol and its co-products is recorded when title transfers to customers. Ethanol and its co-products have generally been shipped FOB our plants. Shipping and handling charges to customers are included in revenues. In accordance with our marketing agreement with Aventine, sales were recorded 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. We expect that our sales of ethanol will generally be recognized upon delivery to our customers at terminals or other locations, rather than upon shipment from our plants.

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 Financial Accounting Standards Board (“FASB”) Statement No. 133, as amended, unless designated otherwise, and therefore are not marked to market in our financial statements.

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 FASB Statement No. 123R, utilizing the modified prospective application method. FASB Statement 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.

The Company uses the Black-Scholes single option pricing model to determine the fair value for employee stock options, which can be affected by the Company’s 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 our estimates to calculate the fair value for employee stock options are not consistent with actual results, we may be exposed to gains or losses that could be material. See Note 4 of our Condensed Consolidated Financial Statements.

Property and equipment: Property and equipment are stated at cost. Depreciation is computed by the straight-line method over the following estimated useful lives as set forth below. Our estimates regarding the useful lives of our depreciable assets are based on our judgment. Accordingly, changes in circumstances such as technological advances or changes to our business model could result in actual useful lives differing from our managements 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.

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

Goodwill: 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. The test for impairment of unamortized other intangible assets is performed on at least an annual basis. We deem unamortized other intangible assets to be impaired if the carrying amount of an asset exceeds its fair value. We test the recoverability of all other long-lived 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 is 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

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 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, we are exposed to various market risks. 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:

Ethanol and Corn Price Comparison


(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. (“Bloomberg”). 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 that are received from the sale of distillers grains.

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. Traditionally, 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 62.5% of our total cost of goods sold for the three months ended March 31, 2007, compared to 43.8% for the three months ended March 31, 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 May 1, 2007, the CBOT price per bushel of corn was $3.68.

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 first quarter of 2007, CBOT corn prices have ranged from a low of $3.55 per bushel to a high of $4.35 per bushel, with prices averaging $4.01 per bushel. These higher corn prices contributed to adverse comparisons in the three-month period ended March 31, 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 10.8% of our cost of goods sold for the three months ended March 31, 2007, compared to 19.7% for the three months ended March 31, 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 million British Thermal Units, or 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 May 1, 2007, the NYMEX price of natural gas was $7.72 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, which may differ from actual results, are as follows:


	Annual						Change in
	Volume			Hypothetical Adverse			Annual
	Requirements		Units	Change in Price			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	)

As of March 31, 2007, approximately 7.5% of our estimated ethanol production for the next twelve months was subject to fixed price contracts and approximately 5.3% was sold on index contracts. In addition, 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 Ended			Three Months Ended			Three Months Ended			Three Months Ended			Twelve Months Ended
	June 30,			September 30,			December 31,			March 31,			March 31,
	2007			2007			2007			2008			2008
Corn (thousands of bushels) (1)		14,510			12,083			4,743			114			31,438
Percentage of estimated requirements		50.5	%		40.0	%		15.5	%		0.4	%		27.7	%
Natural Gas (MMBTU)		—			—			—			—			—
Percentage of estimated requirements		—			—			—			—			—


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

The extent to which we enter into these arrangements during the year may 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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

In connection with the preparation of our annual report on Form 10-K for the year ended December 31, 2006 and our quarterly report on Form 10-Q for the three months ended March 31, 2007, we carried out an evaluation, 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 December 31, 2006 and as of the end of the period covered by this quarterly report, our disclosure controls and procedures were not 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 because of the material weaknesses described below.

To address these weaknesses, we performed additional analyses and other post-closing procedures to ensure that our consolidated financial statements included in our Form 10-K and this report were prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in the Form 10-K and this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Our management is working 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 have enhanced our process relating to determining the fair value of derivative financial instruments. We have also hired an outside service provider to assist us with income tax provisions. 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. Our efforts to remediate the remaining weaknesses are focused on hiring 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 support our remediation efforts.

A material weakness is a significant deficiency, or combination of significant deficiencies in internal controls over financial reporting, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The material weaknesses identified were: inadequate monitoring of accounting recognition matters and significant accounting estimates, including derivative financial instruments and income taxes and deficiencies in our financial closing process. The weaknesses resulted in significant adjustments to our trial balances as of December 31, 2006. As noted above, management believes the potential inaccuracies in financial reporting that resulted from these weaknesses were properly addressed before the completion of our consolidated financial statements for the year ended December 31, 2006 and the three months ended March 31, 2007.

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 62.5% of our total cost of goods sold for the three months ended March 31, 2007, compared to 43.8% for the three months ended March 31, 2006. Over the ten-year period from 1997 through 2006, corn prices (based on the Chicago Board of Trade (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 May 1, 2007, the CBOT price per bushel of corn was $3.68.

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 we do not expect the spread to 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. 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.

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 10.8% of our cost of goods sold for the three months ended March 31, 2007, compared to 19.7% for the three months ended March 31, 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 million British Thermal Units or, 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 May 1, 2007, the NYMEX price of natural gas was $7.72 per MMBTU.

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

Ethanol is marketed both as a fuel additive 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.

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.

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 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 of the 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 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 start-up 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;

	•	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. In addition, if we fail to remediate certain material weaknesses in our internal controls over financial reporting, we may not be able to report our financial results accurately, which could cause investors to lose confidence in our financial reporting.

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.

As required by the Sarbanes-Oxley Act of 2002, we carried out an evaluation in connection with the preparation of our annual report on Form 10-K for the year ended December 31, 2006 and our quarterly report on Form 10-Q for the three months ended March 31, 2007, under the supervision of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon such evaluations as of December 31, 2006 and as of March 31, 2007, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective because of material weaknesses in our internal controls. A material weakness is a significant deficiency, or combination of significant deficiencies in internal controls over financial reporting, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

The material weaknesses identified were: (i) inadequate monitoring of accounting recognition matters and significant accounting estimates, including derivative financial instruments and income taxes and (ii) deficiencies in our financial closing process. The above weaknesses were initially identified in the course of the year-end audit process and resulted in significant adjustments in our trial balances as of December 31, 2006. To address these control deficiencies, we performed additional analyses and other post-closing procedures to ensure that our consolidated financial statements were prepared in accordance with generally accepted accounting principles.

Our management is working with our Audit Committee to identify and implement corrective actions where required to improve our internal controls, including the enhancement of our systems and procedures. We cannot assure you that the remediation will be successful, such remediation will be completed in a timely manner or that we will not incur material costs in connection with the remediation. We also cannot assure you that additional significant or other deficiencies or material weaknesses will not be discovered in the future.

Our failure to remediate the material weaknesses or other control deficiencies or to establish and maintain effective systems of internal and disclosure controls and procedures may impair our ability to accurately report our financial results and prevent fraud. This failure may result in a restatement of our financial statements and may cause investors to lose confidence in our reported financial information, which could have a material adverse effect on our business, operating results, stock price, ability to access capital markets and may increase the cost of any financing we obtain.

We are substantially dependent on three 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 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.

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 Hartley, Welcome and Reynolds facilities 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.

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.

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 commenced commercial operations at our Aurora facility in December 2003, at our Fort Dodge facility in October 2005 and at our Charles City facility in April 2007. 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.

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 has increased from 1.8 BGY as of January 2001 to an estimated 5.9 BGY at April 25, 2007. The RFA estimates that, as of April 25, 2007, approximately 6.6 BGY of additional production capacity is under construction. The ethanol industry in the U.S. now consists of more than 116 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, US BioEnergy Corporation, Hawkeye Renewables, LLC, Aventine Renewable Energy Holdings, Inc., and Cargill, Inc. As of April 25, 2007, the top five producers accounted for approximately 32% 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 to 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 cannot achieve results comparable to those achieved by marketing through Aventine.

On February 15, 2006, we notified Aventine that we were terminating our agreements with it regarding the marketing and sale of our ethanol as of March 31, 2007. As of 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 900 tanker railcars and have contracted with storage depots near our customers and at our strategic locations to ensure 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.

Operations at our Charles City facility 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 start up process. In October 2005, we recommenced our start up activities at the plant and are now operating at full capacity. As a new plant, our Charles City facility is 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 Charles City facility or our additional planned facilities may not be comparable to those of our Aurora or Fort Dodge 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 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 recent Energy Policy Act 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. As the rules for implementation of the RFS and the energy bill are still under development, the impact of legislation is still uncertain.

The legislation did not include MTBE liability protection sought by refiners, which resulted in accelerated removal of MTBE and increased demand for ethanol. However, refineries may use other possible replacement additives, such as iso-octane, iso-octene or alkylate. Accordingly, the demand for ethanol could decrease. In addition, 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, 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.

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 noteholders.

As of April 27, 2007, our executive officers and directors as a group beneficially own approximately 47.5% of our outstanding common stock, including Donald L. Endres, our Chief Executive Officer, who beneficially owns approximately 42.5% 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 March 31, 2007, our total debt was $209.0 million (after unaccreted discount of $1.0 million). As of March 31, 2007, we had total borrowing capacity of $30.0 million under our credit agreement. Letters of credit totaling $2.9 million have been issued and undrawn under the credit agreement, leaving $27.1 million of undrawn borrowing capacity at March 31, 2007. 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. 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.

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

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

The market price of our common stock could fluctuate significantly. Those 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;

	•		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 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

(a). On March 15, 2007, the Company completed the acceptance of the rights to a construction site pursuant to its site acquisition agreement with American Milling, LP. In accordance with that agreement, the Company issued 150,000 shares of Common Stock to an affiliate of American Milling at the closing. The Company is obligated to issue 150,000 additional shares when it obtains certain construction permits relating to the site or one year after the closing, whichever occurs first. The Company relied on the private offering exemption under Section 4(2) of the Securities Act of 1933 to complete this transaction.

(b). On June 13, 2006, our Registration Statement on Form S-1 (Registration No. 333-132861) became effective. A total of 20,987,500 shares of our common stock were registered pursuant to the Registration Statement. The IPO was completed on June 19, 2006. An aggregate of 11,000,000 shares of common stock were sold by the Company and 9,987,500 shares were sold by certain shareholder’s of the Company, which included 2,737,500 shares sold pursuant to an option granted by the shareholder’s to the underwriters to cover over-allotments. The underwriters for the offering were Morgan Stanley & Co. Incorporated, Lehman Brothers Inc. and A.G. Edwards & Sons, Inc.

The IPO price was $23 per share. The Company and the selling shareholders received total proceeds of $235.9 million and $214.2 million, respectively, after deduction of underwriting discounts and commissions of $17.1 million and $15.5 million, respectively. Other expenses payable by the Company related to the IPO were $2.9 million.

As of March 31, 2007, we had applied the $233 million of net proceeds we received from the offering as follows (dollars in millions):


Construction of facilities	$	62.0
Purchase of real estate		24.5
Temporary investments		146.5

None of the foregoing payments were to our directors or officers, or their associates, or to our affiliates or persons owning ten percent or more of our common stock.

ITEM 6. EXHIBITS


3.1		Articles of Incorporation, as amended, of VeraSun Energy Corporation.*

3.2		Bylaws, as amended, of VeraSun Energy Corporation.*

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 Stanly & Co. Incorporated.*

4.3		Revolving Credit Agreement, dated as of December 21, 2005, among VeraSun Energy Corporation, First National Bank of Omaha, VeraSun Aurora Corporation, VeraSun Fort Dodge, LLC and VeraSun Charles City, LLC.*

4.4		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.*

4.5		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 ended September 30, 2006.)

4.6		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, and VeraSun Welcome, LLC, as Subsidiary Guarantors, and Wells Fargo, N.A., as Trustee. (Incorporated by reference to VeraSun Energy Corporation’s Annual Report on Form 10-K for the period ended December 31, 2006.)

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).


	PAGE NO.
PART I. FINANCIAL INFORMATION
Item 1 — Financial Statements
Condensed Consolidated Balance Sheets		1
Condensed Consolidated Statements of Operations		2
Condensed Consolidated Statements of Cash Flows		3
Notes to Condensed Consolidated Financial Statements		4
Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
Item 3 — Quantitative and Qualitative Disclosures About Market Risk		24
Item 4 — Controls and Procedures		25
PART II. OTHER INFORMATION
Item 1A — Risk Factors		27
Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds		38
Item 6 — Exhibits		39
SIGNATURES		40


	VERASUN ENERGY CORPORATION
	By:	/s/ Donald L. Endres
		Donald L. Endres
		Chief Executive Officer and President

	By:	/s/ Danny C. Herron
		Danny C. Herron
		Senior Vice President and Chief Financial Officer

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)		[Reserved]

	c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting and;

1.		I have reviewed this Quarterly Report on Form 10-Q of VeraSun Energy Corporation;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.