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 June 30, 2006


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 22^nd 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 o No þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer þ

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

Yes ¨ No þ

The number of shares of Common Stock outstanding on August 7, 2006 was 75,224,168.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VERASUN ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2006
	(Unaudited)			December 31, 2005
	(dollars in thousands)
Assets
Current Assets
Cash and cash equivalents	$	312,943		$	29,714
Receivables, less allowance for doubtful accounts of $10 for 2006 and 2005		45,211			28,663
Inventories		16,899			19,291
Prepaid expenses		3,502			4,611
Deferred income taxes		1,160			5,839

Total current assets		379,715			88,118


Other Assets
Restricted cash held in escrow		104,672			124,750
Debt issuance costs, net		5,991			6,449
Goodwill		6,129			6,129

		116,792			137,328


Property and Equipment, net		204,259			179,683

	$	700,766		$	405,129


Liabilities and Shareholders Equity
Current Liabilities
Current portion of deferred revenues	$	95		$	95
Accounts payable		15,808			20,055
Accrued expenses		4,355			1,991
Derivative financial instruments		5,398			4,426

Total current liabilities		25,656			26,567


Long-Term Liabilities
Long-term debt		208,812			208,719
Deferred revenues, less current portion		1,663			1,710
Convertible put warrant		—			7,458
Deferred income taxes		20,057			15,757

		230,532			233,644


Shareholders Equity
Preferred stock, $0.01 par value; authorized 25,000,000 and 100,000,000 shares for 2006 and 2005, respectively; none issued or outstanding		—			—
Common stock, $0.01 par value; authorized 250,000,000 shares; 75,224,168 and 62,492,722 shares issued and outstanding as of June 30, 2006 and December 31, 2005, respectively		752			625
Additional paid-in capital		412,783			132,848
Retained earnings		36,150			13,862
Deferred compensation		—			(107	)
Accumulated other comprehensive loss		(5,107	)		(2,310	)

		444,578			144,918

	$	700,766		$	405,129

See Notes to Condensed Consolidated Financial Statements.

VERASUN ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(dollars in thousands, except per share data)
Revenues:
Net sales	$	152,308		$	34,483		$	262,189		$	79,168
Other revenues, incentive income		758			(73	)		1,581			94

Total revenues		153,066			34,410			263,770			79,262
Cost of goods sold		90,130			35,926			171,488			74,607

Gross profit (loss)		62,936			(1,516	)		92,282			4,655
Selling, general and administrative expenses		22,412			2,369			26,182			4,427

Operating income (loss)		40,524			(3,885	)		66,100			228


Other income (expense):
Interest expense, including change in fair value of convertible put warrant		(13,766	)		(1,497	)		(30,062	)		(3,011	)
Interest income		2,302			70			3,970			114
Other income		19			2			21			2

		(11,445	)		(1,425	)		(26,071	)		(2,895	)


Income (loss) before income taxes and minority interest		29,079			(5,310	)		40,029			(2,667	)
Income tax expense (benefit)		9,526			(1,328	)		17,741			(318	)

Income (loss) before minority interest		19,553			(3,982	)		22,288			(2,349	)
Minority interest in net loss of subsidiary		—			72			—			125

Net income (loss)	$	19,553		$	(3,910	)	$	22,288		$	(2,224	)


Earnings (loss) per common share:
Basic	$	0.30		$	(0.09	)	$	0.35		$	(0.05	)
Diluted		0.29			(0.09	)		0.33			(0.05	)

Pro forma amounts as if all subsidiaries were taxable for entire period:
Pro forma income tax expense (benefit)	$	9,526		$	(1,553	)	$	17,741		$	(699	)
Pro forma net income (loss)		19,553			(3,685	)		22,288			(1,843	)

Pro forma earnings (loss) per common share:
Basic	$	0.30		$	(0.09	)	$	0.35		$	(0.04	)
Diluted		0.29			(0.09	)		0.33			(0.04	)

See Notes to Condensed Consolidated Financial Statements.

VERASUN ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2006			2005
	(dollars in thousands)
Cash Flows from Operating Activities
Net income (loss)	$	22,288		$	(2,224	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		4,746			2,231
Amortization of debt issuance costs and debt discount		649			67
Accretion of deferred revenue		(47	)		(48	)
Minority interest in net loss of subsidiary		—			(125	)
Change in fair value of convertible put warrant		19,670			626
Deferred income taxes		10,485			(192	)
Loss on disposal of equipment		10			2,539
Stock-based compensation		19,709			490
Changes in working capital components:
(Increase) decrease in:
Receivables		(16,548	)		5,377
Inventories		2,392			3,744
Prepaid expenses		1,109			473
Increase (decrease) in:
Accounts payable		(8,099	)		(5,163	)
Accrued expenses		2,364			(118	)
Derivative financial instruments		(3,331	)		(1,483	)

Net cash provided by operating activities		55,397			6,194


Cash Flows from Investing Activities
Purchases of property and equipment		(6,117	)		(46,105	)
Proceeds from sale of equipment		838			29

Net cash used in investing activities		(5,279	)		(46,076	)


Cash Flows from Financing Activities
Proceeds from long-term debt		—			34,621
Issuance of common stock		234,155			—
Debt issuance costs paid		(1,044	)		(460	)

Net cash provided by financing activities		233,111			34,161

Net increase (decrease) in cash and cash equivalents		283,229			(5,721	)

Cash and Cash Equivalents
Beginning		29,714			10,296

Ending	$	312,943		$	4,575

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, 2005, which has been derived from audited 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, 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 (“VW”), VeraSun Marketing, LLC (“VM”) and VeraSun BioDiesel, LLC (“VBD”). 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 financial statements prepared in accordance with generally accepted accounting principles in the U.S. have been condensed or omitted pursuant to those rules and regulations. These condensed consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2005 included in the Company’s registration statement on Form S-1 (Registration No. 333-132861) filed March 30, 2006 and amendments thereto (“Form S-1”).

In the opinion of management, the accompanying unaudited condensed consolidated financial statements as of June 30, 2006 and for the three and six month periods ended June 30, 2006 and 2005 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 financial statements. The results of the interim periods are not necessarily indicative of the results for the full year.

Recently issued accounting standards: In July 2006 the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting for uncertainty in tax positions. This interpretation provides that the financial statement effects of a tax position shall initially be recognized when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. This interpretation also may require additional disclosures related to tax positions taken.

The provisions of FIN 48 are effective as of the beginning of fiscal year 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to the opening balance of retained earnings. Management is currently evaluating the impact of adopting FIN 48 on the Company’s financial statements, but does not expect the adoption of this statement to be significant to the financial statements.

Note 2. Inventories

A summary of inventories is as follows:


	June 30,		December 31,
	2006		2005
Corn	$	5,668	$	9,023
Supplies		5,819		3,890
Chemicals		1,392		1,231
Work in process		1,324		1,150
Distillers grains		218		396
Ethanol		2,478		3,601

	$	16,899	$	19,291

Note 3. Shareholders Equity

On June 13, 2006, the Company’s Form S-1 became effective. A total of 20,987,500 shares of common stock were registered pursuant to the Form S-1. The initial public offering (“IPO”) was completed 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 shareholders of the Company, which included 2,737,500 shares sold pursuant to an option granted by the shareholders to the underwriters to cover over-allotments.

The IPO price was $23 per share. The Company and the selling shareholders received total proceeds of $235,992 and $214,207, respectively, after deduction of underwriting discounts of $17,078 and $15,506, respectively.

Note 4. 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 reflect 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.

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 June 30, 2006 and 2005 follows:


				Weighted Average
	Net Income (Loss)			Shares Outstanding		Per Share Amount
2006:
Basic EPS	$	19,553			64,828,596	$	0.30
Effects of dilutive securities:
Stock options and warrants		—			3,655,800		(0.01	)

Diluted EPS	$	19,553			68,484,396	$	0.29


2005:
Basic EPS	$	(3,910	)		43,119,229	$	(0.09	)
Effects of dilutive securities:
Stock options and warrants — antidilutive		—			—		—

Diluted EPS	$	(3,910	)		43,119,229	$	(0.09	)

A reconciliation of net income (loss) and common stock share amounts used in the calculation of basic and diluted EPS for the six months ended June 30, 2006 and 2005 follows:


				Weighted Average
	Net Income (Loss)			Shares Outstanding		Per Share Amount
2006:
Basic EPS	$	22,288			63,627,172	$	0.35
Effects of dilutive securities:
Stock options and warrants		—			3,400,956		(0.02	)

Diluted EPS	$	22,288			67,028,128	$	0.33


2005:
Basic EPS	$	(2,224	)		43,114,741	$	(0.05	)
Effects of dilutive securities:
Stock options and warrants — antidilutive		—			—		—

Diluted EPS	$	(2,224	)		43,114,741	$	(0.05	)

Warrants outstanding for 1,475,681 shares of common stock at an exercise price of $0.52 per share were not included in the computation of diluted EPS for the three and six months ended June 30, 2005 because the related performance conditions had not yet been met. Performance-based stock option awards for 620,041 shares at a weighted average exercise price of $2.08 per share in the three months ended June 30, 2006 and performance-based stock option awards for 730,425 shares at a weighted average exercise price of $1.02 per share in the three and six months ended June 30, 2005 were not included in the computation of diluted EPS since the accounting “grant date” had not yet occurred. Weighted average shares outstanding related to stock options and warrants for 3,933,453 shares and 3,885,724 shares for the three months and six months ended June 30, 2005, respectively, were not included in the calculation of diluted EPS as the effects would be antidilutive.

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

Note 5. Stock-Based Compensation

The Company’s Stock Incentive Plan (“Plan”), which has been approved by shareholders, was implemented on November 13, 2003, and an aggregate amount of 10,000,000 common shares have been reserved for grants to directors, employees, select non-employee agents and independent contractors of the Company in the form of service-based, performance-based or restricted stock awards. The Plan is administered by the Compensation Committee of the Board of Directors, which selects persons eligible to receive awards under the Plan and determines the number, terms, conditions, performance measures and other provisions of the awards.

Compensation expense charged against income for grants under the Plan was $19,709 and $490 for the six months ended June 30, 2006 and 2005, respectively. The total income tax benefit recognized in income for grants under the Plan was $5,352 and $167 for the six months ended June 30, 2006 and 2005, respectively. The Company recognizes compensation expense for awards with graded vesting using the straight line method over the entire vesting period for those awards. No compensation expense was capitalized during these periods.

Cash received from the exercise of awards under the Plan was $217 and $0 for the six months ended June 30, 2006 and 2005, respectively. No significant tax benefit was realized upon the exercise of these awards.

Effective January 1, 2006, the Company adopted FASB Statement No. 123 (revised), Share-Based Payment (“Statement No. 123R”), utilizing the modified prospective application method. Prior to the adoption of FASB Statement No. 123R, the Company accounted for stock-based compensation in accordance with Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations (the intrinsic value method), and, therefore, only recognized expense for performance-based option and restricted stock awards for periods prior to January 1, 2006.

Under the modified prospective approach, FASB 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 recognized in the first and second quarters of fiscal year 2006 included 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 included 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 FASB Statement No. 123R. Prior periods were not restated to reflect the impact of adopting the new standard.

As a result of adopting FASB Statement No. 123R on January 1, 2006, income before income taxes and minority interest, net income, cash flows from operating activities, cash flows from financing activities and basic and diluted EPS for the six months ended June 30, 2006 were lower by $12,651, $10,423, $0, $0, $0.16 and $0.16, respectively, than if the Company had continued to account for stock-based compensation under APB Opinion No. 25 for awards under the Plan.

The following table illustrates the pro forma effect on net loss and per share information had the Company accounted for stock-based compensation in accordance with FASB Statement No. 123R for the three and six months ended June 30, 2005:


	Three Months Ended			Six Months Ended
	June 30, 2005			June 30, 2005
Net loss, as reported	$	(3,910	)	$	(2,224	)
Add actual stock-based compensation expense related to performance-based option and restricted stock awards included in reported net loss, net of related tax effects		167			323
Deduct total pro forma stock-based compensation expense determined under the intrinsic value method for all awards, net of related tax effects		(181	)		(567	)

Pro forma net loss	$	(3,924	)	$	(2,468	)


Basic EPS:
As reported	$	(0.09	)	$	(0.05	)
Pro forma		(0.09	)		(0.06	)
Diluted EPS:
As reported	$	(0.09	)	$	(0.05	)
Pro forma		(0.09	)		(0.06	)

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

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; those awards generally vest based on five years of continuous service and have 10-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. 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 was based on the stock volatility for a comparable publicly traded company. 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 date options become exercisable (generally five years) and the date at which they expire (generally 10 years). The risk-free interest rate for periods within the contractual life of the Service Award is based on the U.S. Treasury yield curve in effect at the time of grant.


	Six Months Ended June 30,
	2005		2006
Expected volatility		58%		58%
Expected dividend yield	None		None
Expected term	8 - 10 years		8 - 10 years
Risk-free interest rate		4.4%	4.8% - 4.9%

The following table lists Service Award activity under the Plan for the six months ended June 30, 2006:


				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
Options	Shares			Price		Term		Value
Outstanding at January 1, 2006		2,869,651		$	1.99
Granted		1,436,005			21.39
Forfeited		(46,673	)		1.59
Exercised		(146,277	)		1.05

Outstanding at June 30, 2006		4,112,706		$	8.80		8.6	$	71,744

Vested or expected to vest as of June 30, 2006		4,070,110		$	8.66		8.6	$	71,535

Exercisable at June 30, 2006		2,692,825		$	2.19		8.0	$	64,755

The Company applied a forfeiture rate of 3% when calculating the amount of options expected to vest as of June 30, 2006. This rate is based on historical activity. The weighted average grant date fair value of options granted during the six months ended June 30, 2006 and 2005 was $14.26 and $3.33, respectively. The total intrinsic value of options exercised during the six months ended June 30, 2006 was $3,685. No options were exercised during the six months ended June 30, 2005.

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.

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

The following table shows the status of the Company’s nonvested Restricted Stock as of June 30, 2006 and changes during the six months ended June 30, 2006:


				Weighted
				Average
				Grant Date
Restricted Stock	Shares			Fair Value
Nonvested at January 1, 2006		108,328		$	0.99
Granted		367,285			23.00
Vested		(155,278	)		18.94

Nonvested at June 30, 2006		320,335		$	17.53

As of June 30, 2006, there was $26,922 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 five years. The total fair value of shares vested during the six months ended June 30, 2006 and 2005 was $1,187 and $54, respectively. The grant date fair value of nonvested shares was determined using the value of the Company’s common stock sold near the date of grant.

Performance-Based Awards

Performance-based option awards (“Performance Awards”) under the Plan are generally awarded at the January meeting of the Company’s Board of Directors. The vesting of Performance Awards is contingent upon meeting various individual, departmental and company-wide goals. Performance Awards are generally granted with an exercise price equal to the market price of the Company’s common stock at the date of grant, contingently vest over a period of one year and have 10-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. Certain Performance 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 Performance Award was estimated at the date of grant using the same option valuation model used for Service Awards granted under the Plan and assumes that performance goals will be achieved at a rate of 97 percent. If such goals are not met, or are met at a rate less than 97 percent, compensation expense is adjusted to the appropriate amount to be recognized and any recognized compensation expense above that amount is reversed. The inputs for expected volatility, expected dividend yield and risk-free interest rate used in estimating the fair value of Performance Awards are the same as those noted in the table described for Service Awards. The expected term for Performance Awards granted under the Plan during the six months ended June 30, 2006 is eight years.

The following table lists Performance Award activity under the Plan for the six months ended June 30, 2006:


						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
Options	Shares			Price		Term		Value
Outstanding at January 1, 2006		453,251		$	1.02
Granted		889,409			1.95
Forfeited		(667	)		5.16
Exercised		(54,234	)		1.06

Outstanding at June 30, 2006		1,287,759		$	1.66		7.8	$	31,659

Vested or expected to vest as of June 30, 2006		1,287,759		$	1.66		7.8	$	31,659

Exercisable at June 30, 2006		1,287,759		$	1.66		7.8	$	31,659

The weighted average grant date fair value of Performance Awards granted was $16.61 and $3.39 for the six months ended June 30, 2006 and 2005, respectively. The aggregate intrinsic value of Performance Awards exercised during the six months ended June 30, 2006 and 2005 was $1,366 and $0, respectively. As of June 30, 2006, there was no unrecognized compensation expense related to Performance Awards because all outstanding Performance Awards vested upon completion of the IPO on June 19, 2006.

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

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 other officers of the Advisor. The aggregate intrinsic value of this warrant as of June 30, 2006 was $2,479. No shares have been issued under the warrant and no expense has been recognized by the Company.

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 June 30, 2006, warrants for 485,733 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. No warrants have been exercised and no compensation expense was recognized by the Company in connection with the grant of these warrants. As of June 30, 2006, there was $20 of unrecognized compensation expense related to these warrants and the aggregate intrinsic value of the outstanding amounts was $14,873.

Performance- and Market-Based Awards: In 2002, the Company granted “claw back” warrants to purchase 1,475,681 shares of common stock to certain employees of the Company. The warrants were fully exercisable as of June 30, 2006 at an exercise price of $0.52 per share and expire on June 14, 2016. The total fair value of these warrants at the date of grant was $141, which the Company recognized as compensation expense in the six months ended June 30, 2006, when performance conditions were met upon the completion of the IPO. The aggregate intrinsic value of these warrants as of June 30, 2006 was $37,955.

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

Note 6. Convertible Put Warrant

The Company entered into a subordinated note purchase agreement in 2002, which provided for a commitment to issue subordinated secured notes in an aggregate principal amount of up to $20,000. During 2005, these notes were paid in full. To induce the subordinated note holder (“SNH”) to enter into the note purchase agreement and to make extensions of credit thereunder, the Company granted a warrant to acquire 1,180,000 shares of common stock under the terms of the warrant agreement at an exercise price of $0.01 per share. The computed value of the warrant was $7,458 at December 31, 2005, primarily based upon the estimated fair value of the related common stock. In connection with the completion of the IPO, the put feature was terminated and the warrant was exercised with the underlying shares sold; therefore, the full value of the warrant was reclassified as shareholders equity and the liability associated with the warrant on the balance sheet was no longer outstanding at June 30, 2006. During the six months ended June 30, 2006 and 2005, the change in the computed value of the warrant included in interest expense in the accompanying statements of operations was $19,670 and $626, respectively. The expense recognized in the six months ended June 30, 2006 included the adjustment of the liability related to the warrant to the IPO price of $23 per share of common stock.

Note 7. Comprehensive Income (Loss)

Comprehensive income was $17,365 and comprehensive loss was $2,715 for the three months ended June 30, 2006 and 2005, respectively, and the comprehensive income was $19,491 and comprehensive loss was $1,566 for the six months ended June 30, 2006 and 2005, respectively. The difference between comprehensive income (loss) 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.

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

Note 8. 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 and VW. The Company’s remaining operations are aggregated and classified as “All Other”. Financial performance is evaluated based on operating income (loss) for each of the Company’s subsidiaries, and the accounting policies are applied to the enterprise consistently. 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 is as follows:


	Three Months Ended June 30, 2006
	Ethanol		All
	Production		Other			Totals
Revenues from external customers	$	151,334	$	974		$	152,308
Segment operating income (loss)		60,243		(19,719	)		40,524


	Three Months Ended June 30, 2005
	Ethanol			All
	Production			Other			Totals
Revenues from external customers	$	34,483		$	—		$	34,483
Segment operating (loss)		(3,753	)		(132	)		(3,885	)


	Six Months Ended June 30, 2006
	Ethanol		All
	Production		Other			Totals
Revenues from external customers	$	260,561	$	1,628		$	262,189
Segment operating income (loss)		86,865		(20,765	)		66,100
Segment assets		264,012		436,754			700,766


	Six Months Ended June 30, 2005
	Ethanol		All
	Production		Other			Totals
Revenues from external customers	$	79,168	$	—		$	79,168
Segment operating income (loss)		432		(204	)		228
Segment assets		233,071		172,058			405,129

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

Note 9. 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, VM and VW, each 100% wholly-owned subsidiaries of VEC, are combined as guarantors.

CONDENSED CONSOLIDATING BALANCE SHEET
JUNE 30, 2006
ASSETS


	Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated

Current Assets
Cash and cash equivalents	$	316,368	$	—	$	—	$	(3,425	)	$	312,943
Receivables		11,989		45,907		78		(12,763	)		45,211
Inventories		—		17,025		—		(126	)		16,899
Prepaid expenses		753		2,749		—		—			3,502
Deferred income taxes		223		937		—		—			1,160

Total current assets		329,333		66,618		78		(16,314	)		379,715


Other Assets
Restricted cash held in escrow		104,672		—		—		—			104,672
Investment in subsidiaries		106,305		—		—		(106,305	)		—
Debt issuance costs, net		5,991		—		—		—			5,991
Intercompany notes receivable		105,543		11,500		—		(117,043	)		—
Goodwill		6,129		—		—		—			6,129

		328,640		11,500		—		(223,348	)		116,792


Property and Equipment, net		242		202,222		1,795		—			204,259

Total assets	$	658,215	$	280,340	$	1,873	$	(239,662	)	$	700,766

LIABILITIES AND SHAREHOLDERS AND MEMBERS EQUITY (DEFICIT)


	Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated

Current Liabilities
Outstanding checks in excess of bank balance	$	—		$	3,425		$	—		$	(3,425	)	$	—
Current maturities of long-term debt		—			21,857			—			(21,857	)		—
Current portion of deferred revenues		—			95			—			—			95
Accounts payable		(9,760	)		25,586			837			(855	)		15,808
Accrued expenses		3,088			9,548			95			(8,376	)		4,355
Derivative financial instruments		—			5,398			—			—			5,398

Total current liabilities		(6,672	)		65,909			932			(34,513	)		25,656


Long-Term Liabilities
Long-term debt, less current maturities		220,311			85,763			1,456			(98,718	)		208,812
Deferred revenues, less current portion		—			1,663			—			—			1,663
Deferred income taxes		(2	)		20,241			(182	)		—			20,057

		220,309			107,667			1,274			(98,718	)		230,532


Shareholders and Members Equity (Deficit)
Common stock		752			20,924			—			(20,924	)		752
Additional paid-in capital		412,783			26,891			—			(26,891	)		412,783
Retained earnings		36,150			64,356			(333	)		(64,023	)		36,150
Members equity (deficit)		—			(300	)		—			300			—
Accumulated other comprehensive loss		(5,107	)		(5,107	)		—			5,107			(5,107	)

		444,578			106,764			(333	)		(106,431	)		444,578

	$	658,215		$	280,340		$	1,873		$	(239,662	)	$	700,766

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 June 30, 2006


	Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated

Revenues	$	—		$	154,339		$	—		$	(1,273	)	$	153,066
Cost of goods sold		985			90,279			13			(1,147	)		90,130

Gross profit (loss)		(985	)		64,060			(13	)		(126	)		62,936
Selling, general and administrative expenses		18,105			4,203			104			—			22,412

Operating income (loss)		(19,090	)		59,857			(117	)		(126	)		40,524
Other income (expense):
Interest expense, including change in fair value of convertible put warrant		(14,982	)		(3,661	)		(41	)		4,918			(13,766	)
Interest income		6,370			850			—			(4,918	)		2,302
Equity in earnings of subsidiaries		35,707			—			—			(35,707	)		—
Other income		—			19			—			—			19

Income (loss) before income taxes		8,005			57,065			(158	)		(35,833	)		29,079
Income tax expense (benefit)		(11,548	)		21,132			(58	)		—			9,526

Net income (loss)	$	19,553		$	35,933		$	(100	)	$	(35,833	)	$	19,553

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2006


	Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated

Revenues	$	—		$	265,043		$	—		$	(1,273	)	$	263,770
Cost of goods sold		985			171,637			13			(1,147	)		171,488

Gross profit (loss)		(985	)		93,406			(13	)		(126	)		92,282
Selling, general and administrative expenses		18,955			7,050			177			—			26,182

Operating income (loss)		(19,940	)		86,356			(190	)		(126	)		66,100
Other income (expense):
Interest expense, including change in fair value of convertible put warrant		(31,730	)		(7,314	)		(81	)		9,063			(30,062	)
Interest income		11,840			1,193			—			(9,063	)		3,970
Equity in earnings of subsidiaries		50,232			—			—			(50,232	)		—
Other income		—			21			—			—			21

Income (loss) before income taxes		10,402			80,256			(271	)		(50,358	)		40,029
Income tax expense (benefit)		(11,886	)		29,727			(100	)		—			17,741

Net income (loss)	$	22,288		$	50,529		$	(171	)	$	(50,358	)	$	22,288

VERASUN ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Unaudited) (Continued)

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 2006


	Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated

Net Cash Provided By (Used In) Operating Activities	$	30,382		$	62,145		$	(51	)	$	(37,079	)	$	55,397


Cash Flows from Investing Activities
Purchases of property and equipment		19,871			(25,201	)		(787	)		—			(6,117	)
Proceeds from sale of equipment		—			—			838			—			838

Net cash provided by (used in) investing activities		19,871			(25,201	)		51			—			(5,279	)


Cash Flows from Financing Activities
Outstanding checks in excess of bank balance		—			234			—			(234	)		—
Proceeds from issuance of common stock		234,155			—			—			—			234,155
Retained earnings in subsidiaries		99			(99	)		—			—			—
Principal payments on long-term debt		—			(37,079	)		—			37,079			—
Debt issuance costs paid		(1,044	)		—			—			—			(1,044	)

Net cash provided by (used in) financing activities		233,210			(36,944	)		—			36,845			233,111

Net increase in cash and cash equivalents		283,463			—			—			(234	)		283,229

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

Cash and Cash Equivalents, end of period	$	316,368		$	—		$	—		$	(3,425	)	$	312,943

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

CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2005
ASSETS


	Issuer		Guarantor		Non-Guarantors		Eliminations			Consolidated

Current Assets
Cash and cash equivalents	$	32,905	$	—	$	—	$	(3,191	)	$	29,714
Receivables		995		29,001		—		(1,333	)		28,663
Inventories		—		19,291		—		—			19,291
Prepaid expenses		2		4,609		—		—			4,611
Deferred income taxes		405		5,434		—		—			5,839

Total current assets		34,307		58,335		—		(4,524	)		88,118


Other Assets
Restricted cash held in escrow		124,750		—		—		—			124,750
Investment in subsidiaries		58,968		—		—		(58,968	)		—
Debt issuance costs, net of amortization		6,449		—		—		—			6,449
Intercompany notes receivable		147,786		15,214				(163,000	)		—
Goodwill		6,129		—		—		—			6,129

		344,082		15,214		—		(221,968	)		137,328


Property and Equipment, net		10		178,055		1,618		—			179,683

	$	378,399	$	251,604	$	1,618	$	(226,492	)	$	405,129

LIABILITIES AND SHAREHOLDERS AND MEMBERS EQUITY (DEFICIT)


	Issuer			Guarantor			Non-Guarantors			Eliminations			Consolidated

Current Liabilities
Outstanding checks in excess of bank balance	$	—		$	3,191		$	—		$	(3,191	)	$	—
Current maturities of long-term debt		—			250			—			(250	)		—
Current portion of deferred revenues		—			95			—			—			95
Accounts payable		1,393			18,477			711			(526	)		20,055
Accrued expenses		685			2,105			8			(807	)		1,991
Derivative financial instruments		—			4,426			—			—			4,426

Total current liabilities		2,078			28,544			719			(4,774	)		26,567


Long-Term Liabilities
Long-term debt, less current maturities		223,933			146,388			1,148			(162,750	)		208,719
Deferred revenues, less current portion		—			1,710			—			—			1,710
Convertible put warrant		7,458			—			—			—			7,458
Deferred income taxes		12			15,832			(87	)		—			15,757

		231,403			163,930			1,061			(162,750	)		233,644


Shareholders and Members Equity (Deficit)
Common stock		625			—			—			—			625
Additional paid-in capital		132,848			25,263			—			(25,263	)		132,848
Retained earnings		13,862			21,592			—			(21,592	)		13,862
Members equity (deficit)		—			14,585			(162	)		(14,423	)		—
Deferred compensation		(107	)		—			—			—			(107	)
Accumulated other comprehensive loss		(2,310	)		(2,310	)		—			2,310			(2,310	)

		144,918			59,130			(162	)		(58,968	)		144,918

	$	378,399		$	251,604		$	1,618		$	(226,492	)	$	405,129

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 June 30, 2005


	Issuer		Guarantors			Non-Guarantors			Eliminations			Consolidated

Revenues	$	—	$	34,410		$	—		$	—		$	34,410
Cost of goods sold		—		35,923			3			—			35,926

Gross profit (loss)		—		(1,513	)		(3	)		—			(1,516	)
Selling, general and administrative expenses		—		2,239			130			—			2,369

Operating loss		—		(3,752	)		(133	)		—			(3,885	)
Other income (expense):
Interest expense, including change in fair value of convertible put warrant		—		(1,497	)		—			—			(1,497	)
Interest income		—		69			1			—			70
Equity in earnings (loss) of subsidiaries		—		(121	)		(24	)		145			—
Other income		—		2			10			(10	)		2

Loss before income taxes and minority interest		—		(5,299	)		(146	)		135			(5,310	)
Income tax benefit		—		(1,328	)		—			—			(1,328	)

Loss before minority interest		—		(3,971	)		(146	)		135			(3,982	)
Minority interest in net loss of subsidiary		—		—			—			72			72

Net loss	$	—	$	(3,971	)	$	(146	)	$	207		$	(3,910	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2005


	Issuer		Guarantors			Non-Guarantors			Eliminations		Consolidated

Revenues	$	—	$	79,262		$	—		$	—	$	79,262
Cost of goods sold		—		74,604			3			—		74,607

Gross profit (loss)		—		4,658			(3	)		—		4,655
Selling, general and administrative expenses		—		4,226			201			—		4,427

Operating income (loss)		—		432			(204	)		—		228
Other income (expense):
Interest expense, including change in fair value of convertible put warrant		—		(3,011	)		—			—		(3,011	)
Interest income		—		112			2			—		114
Equity in earnings (loss) of subsidiaries		—		(209	)		(24	)		233		—
Other income		—		2			—			—		2

Loss before income taxes and minority interest		—		(2,674	)		(226	)		233		(2,667	)
Income tax benefit		—		(318	)		—			—		(318	)

Loss before minority interest		—		(2,356	)		(226	)		233		(2,349	)
Minority interest in net loss of subsidiary		—		—			—			125		125

Net loss	$	—	$	(2,356	)	$	(226	)	$	358	$	(2,224	)

VERASUN ENERGY CORPORATION

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

(dollars in thousands, except per share data)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Six Months Ended June 30, 2005


	Issuer		Guarantors			Non-Guarantors			Eliminations		Consolidated

Net Cash Provided By (Used In) Operating Activities	$	—	$	6,436		$	(242	)	$	—	$	6,194


Cash Flows from Investing Activities
Purchases of property and equipment		—		(46,069	)		(36	)		—		(46,105	)
Proceeds from sale of equipment		—		29			—			—		29

Net cash (used in) investing activities		—		(46,040	)		(36	)		—		(46,076	)


Cash Flows from Financing Activities
Debt issuance costs paid		—		(460	)		—			—		(460	)
Proceeds from long-term debt		—		34,621			—			—		34,621

Net cash provided by financing activities		—		34,161			—			—		34,161

Net decrease in cash and cash equivalents		—		(5,443	)		(278	)		—		(5,721	)

Cash and Cash Equivalents, beginning of period		—		10,000			296			—		10,296

Cash and Cash Equivalents, end of period	$	—	$	4,557		$	18		$	—	$	4,575

Note 10. Material Contingencies

In March 2006, the Company entered into agreements for the engineering and construction of the VCC facility. The Company anticipates that the amount held in escrow for the engineering and construction of the VCC facility will be adequate to pay amounts due under these contracts.

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 registration statement on Form S-1 (Registration No. 333-132861) filed on March 30, 2006 and amendments thereto (“Form S-1”). VeraSun Energy Corporation and its subsidiaries are collectively referred to as the “Company”, “we”, “us” and “our”.

This quarterly report 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 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

We are the second largest ethanol producer in the U.S. based on production capacity, according to the Renewable Fuels Association, or RFA. We are also the largest “pure-play” ethanol producer, focusing 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.

We own and operate two of the largest ethanol production facilities in the U.S., with a combined ethanol production capacity of 230 million gallons per year, or MMGY. We refer to our operating facilities in Aurora, South Dakota and Fort Dodge, Iowa as our Aurora Facility and Fort Dodge Facility, respectively. As of July 26, 2006, our ethanol production capacity represented approximately 5% of the total ethanol production capacity in the U.S., according to the RFA. 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 addition to our two operating facilities, we are constructing a third facility in Charles City, Iowa, the Charles City Facility, and expect to commence construction on two additional facilities in Hartley, Iowa and Welcome, Minnesota, the Northwestern Iowa Facility and the Welcome Facility respectively, in the fourth quarter of 2006. The construction costs for the Charles City Facility are expected to be paid from funds in escrow, and we plan to finance the construction costs of the Northwestern Iowa Facility and the Welcome Facility with the net proceeds from our initial public offering, or IPO, and from our cash flows from operations. We intend to replicate our successful construction and production processes at these three new facilities. We expect our aggregate production capacity to be 340 MMGY by the end of August 2007 and 560 MMGY by the end of the first quarter of 2008.

Financial Performance Overview

As a commodity-based business, we are subject to a variety of market factors, including the price relationship between ethanol and corn. During the six months ended June 30, 2006, we experienced strong ethanol demand due to the phase-out of methyl tertiary-butyl ether, or MTBE, leading to tightened ethanol supply and favorable ethanol prices. In the first six months of 2006, we experienced an historically wide spread between the price of ethanol and the price of corn, as shown in the following graph:

Ethanol and Corn Price Comparison (1)


(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 wet and dry distillers grains.

As of June 30, 2006, approximately 30% of our estimated ethanol production for the remainder of 2006 was subject to fixed price contracts and approximately 19% was sold on index contracts where a price has been established with an exchange-traded unleaded gasoline futures contract. 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 remainder of 2006:


	Six Months Ending December 31, 2006
			Percentage of
			Estimated
	Quantity		Requirements
Corn (thousands of bushels)(2)		41,174		29	%
Natural gas (MMBTU)		1,760,000		45	%


(2)		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. See “Critical Accounting Policies and Estimates” below.

As of June 30, 2006, far higher percentages of our forward ethanol sales and our corn and natural gas purchase requirements for the remainder of 2006 were subject to fixed price arrangements in the third quarter of 2006 than in the fourth quarter of 2006. 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.

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 (dollars in thousands):


	Three Months Ended June 30,										Six Months Ended June 30,
	2006					2005					2006					2005
	(Unaudited)
Total revenues	$	153,066		100.0	%	$	34,410		100.0	%	$	263,770		100.0	%	$	79,262		100.0	%
Cost of goods sold		90,130		58.9			35,926		104.4			171,488		65.0			74,607		94.1

Gross profit (loss)		62,936		41.1			(1,516	)	(4.4	)		92,282		35.0			4,655		5.9
Selling, general and administrative expenses		22,412		14.6			2,369		6.9			26,182		9.9			4,427		5.6

Operating income (loss)		40,524		26.5			(3,885	)	(11.3	)		66,100		25.1			228		0.3
Other expenses, net		(11,445	)	(7.5	)		(1,425	)	(4.1	)		(26,071	)	(9.9	)		(2,895	)	(3.7	)

Income(loss) before income taxes and Minority interest		29,079		19.0			(5,310	)	(15.4	)		40,029		15.2			(2,667	)	(3.4	)
Income tax expense (benefit)		9,526		6.2			(1,328	)	(3.9	)		17,741		6.7			(318	)	(0.4	)

Income (loss) before Minority interest		19,553		12.8			(3,982	)	(11.6	)		22,288		8.5			(2,349	)	(3.0	)
Minority interest in net loss of subsidiary		—		—			72		0.2			—		—			125		0.2

Net income (loss)	$	19,553		12.8	%	$	(3,910	)	(11.4	)%	$	22,288		8.5	%	$	(2,224	)	(2.8	)%

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Operating data:
Ethanol sold (gallons)		57,104		21,076		111,585		45,772
Average gross price of ethanol sold per gallon	$	2.39	$	1.35	$	2.09	$	1.43
Average corn cost per bushel		2.17		2.31		2.02		2.33
Average natural gas cost per MMBTU		7.75		6.96		8.69		6.93
Average co-product price per ton (net)		83		89		84		94

Other financial data:
EBITDA(1)	$	45,227	$	(2,674)	$	74,837	$	2,700


(1)		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.

Our management believes that EBITDA is useful 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 is not a measure of financial performance under generally accepted accounting principles in the U.S., or GAAP, and should not be considered an alternative to net income, or any other measure of performance under GAAP, or to cash flows from operating, investing or financing activities as an indicator of cash flows or as a measure of liquidity. 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 June 30,					Six Months Ended June 30,
	2006		2005			2006		2005
Net income (loss)	$	19,553	$	(3,910	)	$	22,288	$	(2,224	)
Depreciation		2,382		1,067			4,746		2,231
Interest expense		13,766		1,497			30,062		3,011
Income tax expense (benefit)		9,526		(1,328	)		17,741		(318	)

EBITDA	$	45,227	$	(2,674	)	$	74,837	$	2,700

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

Total revenues. Net sales increased by $117.8 million, or 341.7%, to $152.3 million for the three months ended June 30, 2006 from $34.5 million for the three months ended June 30, 2005. The increase in net sales was the result of a 170.9% increase in volume sold and an increase in average ethanol prices of $1.04 per gallon, or 77.3%, compared to the three months ended June 30, 2005.

Net sales from ethanol increased $107.8 million, or 382.6%, to $136.0 million for the three months ended June 30, 2006 from $28.2 million for the three months ended June 30, 2005. The average price of ethanol sold was $2.39 per gallon for the three months ended June 30, 2006, compared to $1.35 per gallon for the three months ended June 30, 2005.

The net loss from derivatives included in net sales was $1.9 million for the three months ended June 30, 2006, compared to a net loss of $832,000 for the three months ended June 30, 2005. See “Critical Accounting Policies and Estimates” below.

Net sales from co-products increased $7.9 million, or 129.7%, to $14.0 million for the three months ended June 30, 2006 from $6.1 million for the three months ended June 30, 2005. Co-product sales increased primarily as a result of the additional production volume from the Fort Dodge Facility.

Net sales of VE85^tm, our branded E85 product, increased $2.1 million to $2.3 million for the three months ended June 30, 2006 from $200,000 for the three months ended June 30, 2005, primarily due to an increase in the number of retail outlets selling our product.

Cost of goods sold and gross profit. Gross profit increased $64.5 million to $62.9 million for the three months ended June 30, 2006 from a loss of $1.5 million for the three months ended June 30, 2005. The increase was primarily the result of the additional gallons sold and the higher average ethanol price realized in the 2006 period. Ethanol production increased by 36.0 million gallons, or 173.0%, primarly as a result of the Fort Dodge Facility being operational in the 2006 period and the completion of the Aurora Facility expansion project at the end of June 2005.

Corn costs increased $25.5 million to $43.0 million for the three months ended June 30, 2006 from $17.5 million for the three months ended June 30, 2005. Corn costs represented 47.7% of our cost of goods sold before taking into account our co-product sales and 32.1% of our cost of goods sold after taking into account co-product sales for the three months ended June 30, 2006, compared to 48.9% of our cost of goods sold before taking into account our co-product sales and 31.9% of our cost of goods sold after taking into account co-product sales for the three months ended June 30, 2005. The increase was primarily the result of increased production volume from the Fort Dodge Facility for the three months ended June 30, 2006.

Natural gas costs increased $8.8 million to $13.5 million for the three months ended June 30, 2006 from $4.7 million for the three months ended June 30, 2005, and accounted for 15.0% of our cost of goods sold for the three months ended June 30, 2006, compared to 13.1% of our cost of goods sold for the three months ended June 30, 2005. The increase in natural gas costs was attributable to the 173.0% increase in our production compared to the same period in 2005. The increased cost of natural gas as a percentage of our cost of goods sold was primarily attributable to an increase in natural gas prices per MMBTU in the 2006 period.

Transportation expense increased $9.0 million to $13.9 million for the three months ended June 30, 2006 from $4.9 million for the three months ended June 30, 2005, primarily due to the additional volume of ethanol and co-products shipped and increased rail rates in the 2006 period. Transportation expense accounted for 15.4% of our cost of goods sold for the three months ended June 30, 2006, compared to 13.7% of our cost of goods sold for the three months ended June 30, 2005.

Labor and manufacturing overhead costs increased $3.1 million to $8.7 million for the three months ended June 30, 2006 from $5.7 million for the three months ended June 30, 2005. The increase was primarily due to increased production from the Fort Dodge Facility being operational in the 2006 period and expense related to a stock grant to non-management employees of $1.1 million. There were also $770,000 of charges for the three months ended June 30, 2006 related to accelerated vesting of stock-based compensation awards in connection with our IPO.

The net loss from derivatives included in cost of goods sold was $5.1 million for the three months ended June 30, 2006, compared to a net loss of $1.6 million for the three months ended June 30, 2005. See “Critical Accounting Policies and Estimates” below. We mark our corn position for all exchange traded futures contracts to market.

Selling, general and administrative expenses. Selling, general and administrative expenses increased to $22.4 million for the three months ended June 30, 2006 from $2.4 million for the three months ended June 30, 2005. Of this increase, $16.3 million was due to charges related to accelerated vesting of stock-based compensation awards in connection with our IPO and $1.0 million was due to charges for normal expense related to stock-based compensation awards. The remaining increase was primarily the result of increased management and administrative personnel over the 2005 period in anticipation of the expansion of our business.

Other income (expense). Net other expense increased $10.0 million to $11.4 million for the three months ended June 30, 2006 from $1.4 million for the three months ended June 30, 2005. The increase was primarily due to increased interest expense related to the change in the estimated fair value of a put warrant. The charges related to the change in the estimated fair value of the put warrant were $8.7 million for the three months ended June 30, 2006, compared to $313,000 for the three months ended June 30, 2005. The put warrant was exercised on June 8, 2006 and the underlying shares were sold in the IPO. The remaining increase was attributable to higher debt levels due to the financing for the construction of the Fort Dodge Facility and the Charles City Facility, partially offset by an increase in interest income on cash and cash equivalents and restricted cash not yet expended on construction.

Income taxes. The provision for income tax expense was $9.5 million for the three months ended June 30, 2006 and the income tax benefit was $1.3 million for the three months ended June 30, 2005. The effective tax rate for the three months ended June 30, 2006 was 32.8%, compared to 25.0% for the three months ended June 30, 2005. The increase in effective tax rate was primarily the result of nondeductible expense associated with the increase in the estimated fair value of the put warrant and the accelerated vesting of incentive stock option and restricted stock awards in connection with our IPO.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Total revenues. Net sales increased by $183.0 million, or 231.2%, to $262.2 million for the six months ended June 30, 2006 from $79.2 million for the six months ended June 30, 2005. The increase in net sales was the result of a 143.8% increase in ethanol volume sold and an increase in average ethanol prices of $0.66 per gallon, or 45.4%, compared to the six months ended June 30, 2005.

Net sales from ethanol increased $166.5 million, or 255.5%, to $231.7 million for the six months ended June 30, 2006 from $65.2 million for the six months ended June 30, 2005. The average price of ethanol sold was $2.09 per gallon for the six months ended June 30, 2006, compared to $1.43 per gallon for the six months ended June 30, 2005.

The net loss from derivatives included in net sales was $1.4 million for the six months ended June 30, 2006, compared to a net loss of $1.8 million for the six months ended June 30, 2005. See “Critical Accounting Policies and Estimates” below.

Net sales from co-products increased $13.8 million, or 99.8%, to $27.6 million for the six months ended June 30, 2006 from $13.8 million for the six months ended June 30, 2005. Co-product sales increased primarily as a result of the additional production volume from the Fort Dodge Facility.

Net sales of VE85^tm increased $2.7 million to $2.9 million for the six months ended June 30, 2006 from $211,000 for the six months ended June 30, 2005, primarily due to an increase in the number of retail outlets selling our product.

Cost of goods sold and gross profit. Gross profit increased $87.6 million to $92.3 million for the six months ended June 30, 2006 from $4.7 million for the six months ended June 30, 2005. The increase was the result of the additional gallons sold and the higher average net realized price per gallon of ethanol for the six months ended June 30, 2006 compared to the six months ended June 30, 2005. Ethanol production increased by 65.1 million gallons, or 142.8%, primarily as a result of the Fort Dodge Facility being operational in the 2006 period and the completion of the Aurora Facility expansion project at the end of June 2005.

Corn costs increased $39.8 million to $78.7 million for the six months ended June 30, 2006 from $38.9 million for the six months ended June 30, 2005. Corn costs represented 45.9% of our cost of goods sold before taking into account our co-product sales and 29.8% of our cost of goods sold after taking into account co-product sales for the six months ended June 30, 2006, compared to 52.3% of our cost of goods sold before taking into account our co-product sales and 33.7% of our cost of goods sold after taking into account co-product sales for the six months ended June 30, 2005.

Natural gas costs increased to $29.5 million for the six months ended June 30, 2006 from $9.9 million for the six months ended June 30, 2005, and accounted for 17.2% of our cost of goods sold for the six months ended June 30, 2006, compared to 13.3% of our cost of goods sold for the six months ended June 30, 2005. The increase in natural gas costs was attributable to the 142.8% increase in production compared to the same period in 2005. The increased cost of natural gas as a percentage of our cost of goods sold was primarily attributable to an increase in natural gas prices per MMBTU in the 2006 period.

Transportation expense increased $15.7 million to $26.0 million for the six months ended June 30, 2006 from $10.3 million for the six months ended June 30, 2005, primarily due to additional volume of ethanol and co-products shipped and increased rail rates for the 2006 period. Transportation expense accounted for 15.1% of our cost of goods sold for the six months ended June 30, 2006, compared to 13.9% of our cost of goods sold for the six months ended June 30, 2005.

Labor and manufacturing overhead costs increased $6.9 million to $15.4 million for the six months ended June 30, 2006 from $8.5 million for the six months ended June 30, 2005. The increase was primarily due to the Fort Dodge Facility being operational in the 2006 period as well as $1.9 million of charges for stock-based compensation awards for the six months ended June 30, 2006.

The net loss from derivatives included in cost of goods sold was $6.5 million for the six months ended June 30, 2006, compared to a net loss of $3.2 million for the six months ended June 30, 2005. See “Critical Accounting Policies and Estimates” below.

Selling, general and administrative expenses. Selling, general and administrative expenses increased to $26.2 million for the six months ended June 30, 2006 from $4.4 million for the six months ended June 30, 2005. Of this increase, $16.3 million was due to one-time charges related to accelerated vesting of stock-based compensation awards in connection with our IPO and $1.6 million was due to charges for normal expense related to stock-based compensation awards. The remaining increase was primarily the result of increased management and administrative personnel over the 2005 period in anticipation of the expansion of our business.

Other income (expense). Net other expense increased $23.2 million to $26.1 million for the six months ended June 30, 2006 from $2.9 million for the six months ended June 30, 2005. The increase was primarily due to increased interest expense related to the change in the estimated fair value of a put warrant. The charges related to the change in the estimated fair value of the put warrant were $19.7 million for the six months ended June 30, 2006, compared to $626,000 for the six months ended June 30, 2005. The put warrant was exercised on June 8, 2006 and the underlying shares were sold in the IPO. The remaining increase was attributable to higher debt levels due to the financing for the construction of the Fort Dodge Facility and the Charles City Facility, partially offset by an increase in interest income on cash and cash equivalents and restricted cash not yet expended on construction.

Income taxes. The provision for income tax expense was $17.7 million for the six months ended June 30, 2006 and income tax benefit was $318,000 for the six months ended June 30, 2005. The effective tax rate for the six months ended June 30, 2006 was 44.3%, compared to 11.9% for the six months ended June 30, 2005. The increase in effective tax rate was primarily the result of nondeductible expense associated with the increase in the estimated fair value of the put warrant and the accelerated vesting of incentive stock option and restricted stock awards in connection with our IPO.

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. In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new facilities, capital expenditures, the debt service requirements of our indebtedness and general corporate purposes.

In June 2006, we completed our IPO, selling 11 million shares at $23 per share, with estimated net proceeds to the Company of $233.4 million. Combined with the cash generated from operations in the six months ended June 30, 2006, we had approximately $312.9 million of unrestricted cash and cash equivalents, which is in excess of the estimated $280 million required to fund construction of our Northwestern Iowa Facility and Welcome Facility. We also had approximately $104.7 million of cash in escrow for the construction of the Charles City Facility at June 30, 2006.

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


	Six Months Ended June 30,
	2006			2005
Net cash provided by operating activities	$	55,397		$	6,194
Net cash used in investing activities		(5,279	)		(46,076	)
Net cash provided by financing activities		233,111			34,161

Net increase (decrease) in cash and cash equivalents	$	283,229		$	(5,721	)

We financed our operations during the six months ended June 30, 2006 primarily through cash flows from operating activities. At June 30, 2006, we had total unrestricted cash and cash equivalents of $312.9 million compared to $29.7 million at December 31, 2005. Cash provided by operating activities was $55.4 million for the six months ended June 30, 2006, compared to $6.2 million for the six months ended June 30, 2005. The increase in operating cash flows was primarily due to the startup of the Fort Dodge Facility and the expansion of the Aurora Facility after June 30, 2005.

Cash used in investing activities was $5.3 million for the six months ended June 30, 2006 compared to $46.1 million for the six months ended June 30, 2005. The decrease was due to the completion of construction of the Fort Dodge Facility in October 2005.

Cash provided by financing activities for the six months ended June 30, 2006 was $233.1 million, compared to $34.2 million provided by financing activities for the six months ended June 30, 2005. The 2005 period included borrowings for construction of the Fort Dodge Facility, while the 2006 period included debt issuance costs and estimated net proceeds from our IPO.

As of June 30, 2006, we had total debt of $210.0 million, before $1.2 million of unaccreted debt discount. In addition, we had total borrowing capacity of $29.0 million under our credit agreement. Letters of credit in an aggregate amount of $3.2 million have been issued under our credit agreement, leaving $25.8 million of remaining borrowing capacity at June 30, 2006.

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 requirements through cash and cash equivalents, cash provided by operations and, if necessary, borrowings under our credit agreement. We believe our sources of liquidity will be sufficient to meet the cash requirements of our operations for at least the next twelve months.

In addition to the construction of our Charles City, Northwestern Iowa and Welcome Facilities described below, we may also consider additional opportunities for growing our production capacity, including the development of other sites and the expansion of one or more of our existing facilities. To finance any material acquisitions or joint ventures, expand our operations or make additional capital expenditures we may need to seek additional sources of funding, including from the issuance of additional equity or debt. 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.

Capital expenditures. We expect to make capital expenditures of approximately $150.0 million and $255.0 million in 2006 and 2007, respectively, primarily for construction of our Charles City, Northwestern Iowa and Welcome Facilities.

Charles City Facility construction. We are using $125.0 million of the net proceeds from the issuance of our senior secured notes completed in December 2005 to finance construction and start up costs for our Charles City Facility. We commenced construction of our Charles City Facility in March 2006 and expect the project to be completed by August 2007.

Construction of Northwestern Iowa and Welcome Facilities. We intend to use the net proceeds to us from our IPO to finance a portion of the construction costs of our Northwestern Iowa and our Welcome Facilities at an estimated aggregate cost of $280.0 million, with the balance expected to come from cash-on-hand and cash generated from operations during the construction period. We expect to begin construction at our Northwestern Iowa and Welcome Facilities in the fourth quarter of 2006, with operations commencing by the end of the first quarter of 2008.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on our condensed consolidated financial statements, which have been prepared in conformity with GAAP. The preparation of financial statements requires the use of estimates and assumptions. Accounting estimates are an integral part of the preparation of financial statements and 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 believe that of our significant accounting policies, the following are noteworthy because changes in these estimates or assumptions could materially affect our financial position and results of operations.

Revenue recognition. Revenues from the production of ethanol and its co-products are recorded when title transfers to customers. Ethanol and its co-products are generally shipped FOB our facilities. In accordance with our plan to end our marketing relationship with Aventine Renewable Energy, Inc., or Aventine, FOB terms may change and consequently affect revenue recognition practices in the future. Transportation expenses incurred are recorded as a component of cost of goods sold. In accordance with our marketing agreement with Aventine, sales are recorded net of commissions retained by Aventine at the time payment is remitted.

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 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. Prior to the adoption of FASB Statement No. 123R, we accounted for stock-based compensation in accordance with APB Opinion No. 25, and related interpretations (the intrinsic value method), and, therefore, only recognized stock-based compensation expense for performance-based option and restricted stock awards for periods prior to January 1, 2006. 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. See Note 5 to our Condensed Consolidated Financial Statements.

In connection with the IPO, substantially all of the outstanding options and warrants to purchase our common stock became immediately exercisable due to accelerated vesting provisions within those instruments. This accelerated vesting resulted in a non-cash charge with respect to these options and warrants of $17.1 million, or $12.1 million, net of tax effect. We also incurred a non-cash charge of approximately $1.1 million, or $702,000 net of tax effect, associated with a stock grant to non-management employees in connection with our IPO. These charges, net of tax, plus the interest charges related to the change in estimated fair value of the put warrant exercised June 8, 2006, totaled $21.5 million.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In addition to risks inherent in our operations, we are exposed to various market risks. 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 S-1 and described in Part II, Item 1A of this quarterly report.

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 45.9% of our total cost of goods sold for the six months ended June 30, 2006, compared to 52.3% for the six months ended June 30, 2005. Over the ten-year period from 1996 through 2005, corn prices (based on the CBOT daily futures data) have ranged from a low of $1.75 per bushel in 2000 to a high of $5.48 per bushel in 1996, with prices averaging $2.47 per bushel during this period. At June 30, 2006, the CBOT price per bushel of corn was $2.36.

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 17.2% of our cost of goods sold for the six months ended June 30, 2006, compared to 13.3% for the six months ended June 30, 2005. The price fluctuation in natural gas prices over the six-year period from December 31, 1999 through December 28, 2005, based on the New York Mercantile Exchange, or NYMEX, daily futures data, has ranged from a low of $1.83 per MMBTU in 2001 to a high of $13.91 per MMBTU in 2005, averaging $5.25 per MMBTU during this period. At June 30, 2006, the NYMEX price of natural gas was $5.93 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 2005. Market risk related to these factors is estimated as the potential change in pretax income, resulting from a hypothetical 10.0% adverse change in the fair value of our corn and natural gas requirements and ethanol contracts (based on average prices for 2005) 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:


				Hypothetical
				Adverse			Change in
	Volume			Change in			Annual
	Requirements		Units	Price			Pre-Tax Income
	(in millions)						(in millions)
Corn		46.8	bushels		10.0	%	$	(9.9	)
Ethanol		126.3	gallons		10.0			(20.0	)
Natural gas		4.1	MMBTU		10.0			(3.7	)

As of June 30, 2006, our volume requirements increased approximately 48% for the trailing twelve-month period compared to our volume requirements as of December 31, 2005, primarily as a result of the startup of the Fort Dodge Facility and the expansion of the Aurora Facility. Our exposure to market risk with respect to corn, natural gas and ethanol prices increased correspondingly. We expect that as our production capacity increases, we will be exposed to additional market risk with respect to corn, natural gas and ethanol prices.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures. Our management has evaluated, under the supervision and with the participation of our chief executive officer and chief financial officer, the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on that evaluation, our chief executive officer and chief financial officer have concluded that, as of the end of the period covered by this quarterly report, our disclosure controls and procedures are 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.

Changes in internal control over financial reporting. 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 45.9% of our total cost of goods sold for the six months ended June 30, 2006, compared to 52.3% for the six months ended June 30, 2005. Over the ten-year period from 1996 through 2005, corn prices (based on the CBOT daily futures data) have ranged from a low of $1.75 per bushel in 2000 to a high of $5.48 per bushel in 1996, with prices averaging $2.47 per bushel during this period. At June 30, 2006, the CBOT price per bushel of corn was $2.36.

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. In addition, 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. 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 remain at recent high levels. Our gross margin depends principally on the spread between ethanol and corn prices. During the five-year period from 2001 to 2005, ethanol prices (based on average U.S. ethanol rack prices from Bloomberg) have ranged from a low of $0.94 per gallon to a high of $2.76 per gallon, averaging $1.50 per gallon during this period. In recent periods, the spread between ethanol and corn prices has been at an historically high level, driven in large part by high oil prices and historically low corn prices. During 2005, however, this spread fluctuated widely and 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 a reduction in ethanol prices, would adversely affect our results of operations and financial position.

The market for natural gas is subject to market 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 17.2% of our cost of goods sold for the six months ended June 30, 2006, compared to 13.3% for the six months ended June 30, 2005. The price fluctuations in natural gas prices over the six-year period from December 31, 1999 through December 28, 2005, based on the NYMEX daily futures data, has ranged from a low of $1.83 per MMBTU in 2001 to a high of $13.91 per MMBTU in 2005, averaging $5.25 per MMBTU during this period. At June 30, 2006, the NYMEX price of natural gas was $5.93 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 price decreases. 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 our indexed, gas-plus sales contracts. The price of unleaded gasoline tends to rise during each of the summer and winter. Given our limited history, 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.

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 are substantially dependent on two 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 or that we will 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 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, or associated with issuing additional stock, such as dilution of ownership and earnings.

We must also obtain numerous regulatory approvals and permits in order to construct and operate additional or expanded facilities, including our Northwestern Iowa and Welcome 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. We have not entered into any construction contracts or other arrangements with respect to the construction of our Northwestern Iowa Facility or our Welcome Facility that might limit our exposure to higher costs in developing and completing any new facilities. 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, transportations 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 a solid-fuel combustion 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, solid-fuel combustion 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, dilute shareholder value 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 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.

Acquisitions also frequently result in the recording of goodwill and other intangible assets which are subject to potential impairments in the future that could harm our financial results. In addition, if we finance acquisitions by issuing convertible debt or equity securities, our existing shareholders may be diluted, which could affect the market price of our common stock. 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 our control for our operations, and the ethanol industry generally, to grow. Areas requiring expansion include, but are not limited to:

	•		additional rail capacity;

	•		additional storage facilities for ethanol;

	•		increases in truck fleets capable of transporting ethanol within localized markets;

	•		expansion of refining and blending facilities to handle ethanol;

	•		growth in service stations equipped to handle ethanol fuels; and

	•		growth in the fleet of 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 and at our Fort Dodge Facility in October 2005. 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 an early-stage company and 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;

	•		recruit and retain key personnel;

	•		successfully maintain our 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 quarterly 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 1.9 BGY as of January 2001 to an estimated 4.8 BGY at July 26, 2006. The RFA estimates that, as of July 26, 2006, approximately 2.4 BGY of additional production capacity is under construction. The ethanol industry in the U.S. now consists of more than 90 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 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, Hawkeye Renewables, LLC, Aventine, and Cargill, Inc. As of July 26, 2006, the top ten producers accounted for 46.9% 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 which do not affect the local price of corn grown in the proximity to 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.

We also face increasing competition from international suppliers. Although there is a $0.54 per gallon tariff (which is scheduled to expire in 2007) on foreign produced ethanol that is approximately equal to the blenders’ credit, 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 Aventine does not perform its obligations under existing arrangements or if we cannot achieve results comparable to those achieved by marketing through Aventine once we begin marketing and selling our ethanol directly to customers.

Aventine, a significant competitor of ours, is also the sole buyer of substantially all of our ethanol and we rely heavily on its marketing efforts to successfully sell our product. Because Aventine sells ethanol for itself and a number of other producers, we have limited control over its sales efforts. In addition, a significant portion of our accounts receivable is attributable to Aventine, which is rated significantly below investment grade. If Aventine were to default on payments to us, we would experience a material loss.

On February 15, 2006, we notified Aventine that we will terminate our agreements with it on March 31, 2007. At the expiration of our agreements with Aventine, we intend to market and sell our ethanol directly to blenders, refiners and other end users. The marketing, sales, distribution, transportation, storage or administrative efforts we will need to undertake or arrange may not achieve results comparable to those achieved by marketing through Aventine. Any failure to successfully execute these responsibilities would have a material adverse effect on our results of operations and financial position.

Operations at our Charles City Facility or our additional planned facilities may not achieve results comparable to our Aurora Facility or our Fort Dodge Facility.

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 Fort Dodge Facility is subject, and our Charles City Facility 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. The results of our Charles City Facility or our additional planned facilities may not be comparable to those of our Aurora Facility or our Fort Dodge Facility.

The U.S. ethanol industry is highly dependent upon a myriad of 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 (unless extended) 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. In May 2006, bills were introduced in both the U.S. House of Representatives and U.S. Senate to repeal the $0.54 per gallon 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 this proposed legislation is enacted or if the tariff is not renewed beyond its current expiration in December 2007. 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 use of fuel oxygenates, including ethanol, was mandated through regulation, and much of the forecasted growth in demand for ethanol was expected to result from additional mandated use of oxygenates. Most of this growth was projected to occur in the next few years as the remaining markets switch from MTBE to ethanol. The recently enacted energy bill, however, 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. Because biodiesel and other renewable fuels in addition to ethanol are counted toward the minimum usage requirements of the RFS, 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. In addition, the rules for implementation of the RFS and the energy bill are still under development.

The legislation did not include MTBE liability protection sought by refiners, and ethanol producers have estimated that this will result in accelerated removal of MTBE and increased demand for ethanol. Refineries may use other possible replacement additives, such as iso-octane, iso-octene or alkylate. Accordingly, the actual demand for ethanol may increase at a lower rate than production for estimated demand, resulting in excess production capacity in our industry, which 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.

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.

Any advances in technology which require significant 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.

Our level of indebtedness could adversely affect our ability to react to changes in our business, and we may be limited in our ability to use debt to fund future capital needs.

As of June 30, 2006, our total debt was $210.0 million, before unaccreted discount of $1.2 million. In addition, we had total borrowing capacity of approximately $29.0 million under our credit agreement. Letters of credit in an aggregate amount of $3.2 million have been issued under our credit agreement, leaving $25.8 million of remaining borrowing capacity at June 30, 2006. Our debt service requirements for 2006, based on our outstanding indebtedness as of June 30, 2006, total approximately $20.8 million, which includes interest payments on our senior secured notes and unused commitment fees under our credit agreement. Our substantial indebtedness could have important consequences for you by adversely affecting our financial position. Our substantial indebtedness could:

	•		require us to dedicate a substantial portion of our cash flow from operations to payments with respect to our indebtedness, thereby reducing the availability of our cash flow for working capital, capital expenditures and other general corporate expenditures;

	•		increase our vulnerability to adverse general economic or industry conditions;

	•		limit our flexibility in planning for, or reacting to, competition or changes in our business or industry;

	•		limit our ability to borrow additional funds;

	•		restrict us from building new facilities, making strategic acquisitions, introducing new products or services or exploiting business opportunities; and

	•		place us at a competitive disadvantage relative to competitors that have less debt or greater financial resources.

Our ability to make payments on and refinance our indebtedness will depend on our ability to generate cash from our future operations. Our ability to generate cash from future operations is subject, in large part, to general economic, competitive, legislative and regulatory factors and other factors that are beyond our control. We do not guarantee that we will be able to generate enough cash flow from operations or that we will be able to obtain enough capital to service our debt or fund our planned capital expenditures. In addition, we may need to refinance some or all of our indebtedness on or before maturity. We do not guarantee that we will be able to refinance our indebtedness on commercially reasonable terms or at all. In addition, if we were to default on our payment obligations under another debt instrument, the cross-default provision in our indenture governing the notes would require accelerated payments of principal and interest. We may not be able to generate sufficient cash from operations to satisfy these obligations, especially if other of our debt instruments contain similar cross-default provisions. Our level of indebtedness also could prevent us from having enough cash to redeem the notes at a premium pursuant to the option redemption provisions or upon a change of control.

If we cannot service or refinance our indebtedness, we may have to take actions such as selling assets, seeking additional equity or reducing or delaying capital expenditures, strategic acquisitions, investments or alliances. We may not be able to take these actions, if necessary, on commercially reasonable terms or at all. In addition, our secured lenders could foreclose on and sell our assets if we default on our indebtedness.

Moreover, we have the ability under our debt instruments to incur substantial additional indebtedness, and any additional indebtedness we incur could exacerbate the risks described above.

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

We are or will become subject to reporting and other obligations under the Securities Exchange Act of 1934, as amended, including the requirements of Section 404 of the Sarbanes-Oxley Act. 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 and accounting resources. We anticipate that we will need to upgrade our systems; implement additional financial and management controls, reporting systems and procedures; finish implementing an internal audit function; and hire 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. Any failure to maintain effective internal controls could have a material adverse effect on our business, operating results and stock price.

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 quarterly 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

(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 shareholders of the Company, which included 2,737,500 shares sold pursuant to an option granted by the shareholders 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 $2.5 million.

As of June 30, 2006, we had applied the $233.4 million of net proceeds we received from the offering as follows (dollars in millions):


Construction of facilities	$	0.3
Purchase of real estate		1.9
Temporary investments		232.2

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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

An annual meeting of the shareholders of the Company was held on May 12, 2006. At the meeting, the shareholders approved a reduction in the Company’s authorized preferred stock from 100,000,000 to 25,000,000 shares, increased the number of shares available for issuance under the Company’s Stock Incentive Plan to 10,000,000 shares and ratified certain purchases of common stock in November 2005 for purposes of securing an exemption under Section 16 of the Securities Exchange Act of 1934.

At the annual meeting, the shareholders also approved an amendment to the Company’s articles of incorporation establishing a classified Board of Directors and elected the following seven directors to the classes, with each class of director coming up for election in the year indicated:


		Class I (2007):		Donald L. Endres
				D. Duane Gilliam
				Paul A. Schock

		Class II (2008):		T. Jack Huggins III
				Steven T. Kirby

		Class III (2009):		Mark L. First
				Bruce A. Jamerson

All of the matters presented at the annual meeting, including the election of each director, were approved by a vote of 62,116,113 shares for and no shares against, which represented a 99.2% favorable vote of the 62,593,233 shares of common stock eligible to vote at the meeting. There were no abstentions.

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.*

10.1		Amendment, effective June 18, 2006, to Ethanol Marketing Agreement, dated October 14, 2002, between Aventine Renewable Energy, Inc. (f/k/a Williams Ethanol Services, Inc.) and VeraSun Aurora Corporation (f/k/a/ VeraSun Energy Corporation), as amended on December 8, 2003 and February 22, 2005. (CTR)

10.2		Amendment, effective June 18, 2006, to Ethanol Marketing Agreement, dated February 22, 2005, between Aventine Renewable Energy, Inc. and VeraSun Fort Dodge, LLC. (CTR)

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		2

Condensed Consolidated Statements of Operations		3

Condensed Consolidated Statements of Cash Flows		4

Notes to Condensed Consolidated Financial Statements		5

Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3 – Quantitative and Qualitative Disclosures About Market Risk		27

Item 4 – Controls and Procedures		28

PART II. OTHER INFORMATION

Item 1A – Risk Factors		29

Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds		38

Item 4 – Submission of Matters to a Vote of Security Holders		39

Item 6 – Exhibits		40

SIGNATURE		41


Amendment to Ethanol Marketing Agreement, dated October 14, 2002
Amendment to Ethanol Marketing Agreement, dated February 22, 2005
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906


	VeraSun Energy Corporation

	By:	/s/ Donald L. Endres

		Donald L. Endres
Date: August 7, 2006		*Chief Executive Officer*